UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012.
OR
__ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma | 73-1520922 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
100 West Fifth Street, Tulsa, OK | 74103 |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Common stock, par value of $0.01 | New York Stock Exchange |
(Title of each class) | (Name of each exchange on which registered) |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No __
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X
Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one) Large accelerated filer X Accelerated filer __ Non-accelerated filer __ Smaller reporting company __
Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes__ No X
Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 30, 2012, was $8.2 billion.
On February 19, 2013, the Company had 204,994,065 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 22, 2013, are incorporated by reference in Part III.
ONEOK, Inc.
2012 ANNUAL REPORT
Page No. | |||
As used in this Annual Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
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GLOSSARY
The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
AFUDC | Allowance for funds used during construction |
Annual Report | Annual Report on Form 10-K for the year ended December 31, 2012 |
ASU | Accounting Standards Update |
Bbl | Barrels, 1 barrel is equivalent to 42 United States gallons |
Bbl/d | Barrels per day |
BBtu/d | Billion British thermal units per day |
Bcf | Billion cubic feet |
Bcf/d | Billion cubic feet per day |
Bighorn Gas Gathering | Bighorn Gas Gathering, L.L.C. |
Btu(s) | British thermal units, a measure of the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit |
Bushton Plant | Bushton Natural Gas Processing and Fractionation Plant |
CFTC | Commodities Futures Trading Commission |
Clean Air Act | Federal Clean Air Act, as amended |
Clean Water Act | Federal Water Pollution Control Act Amendments of 1972, as amended |
Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 |
DOT | United States Department of Transportation |
EBITDA | Earnings before interest expense, income taxes, depreciation and amortization |
EPA | United States Environmental Protection Agency |
Exchange Act | Securities Exchange Act of 1934, as amended |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | Accounting principles generally accepted in the United States of America |
Guardian Pipeline | Guardian Pipeline, L.L.C. |
Intermediate Partnership | ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P. |
IRS | Internal Revenue Service |
KCC | Kansas Corporation Commission |
KDHE | Kansas Department of Health and Environment |
LDCs | Local distribution companies |
LIBOR | London Interbank Offered Rate |
MBbl | Thousand barrels |
MBbl/d | Thousand barrels per day |
Mcf | Thousand cubic feet |
MDth/d | Thousand dekatherms per day |
Midwestern Gas Transmission | Midwestern Gas Transmission Company |
MMBbl | Million barrels |
MMBtu | Million British thermal units |
MMBtu/d | Million British thermal units per day |
MMcf | Million cubic feet |
MMcf/d | Million cubic feet per day |
Moody’s | Moody’s Investors Service, Inc. |
Natural Gas Act | Natural Gas Act of 1938, as amended |
Natural Gas Policy Act | Natural Gas Policy Act of 1978, as amended |
NGL products | Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline |
NGL(s) | Natural gas liquid(s) |
Northern Border Pipeline | Northern Border Pipeline Company |
NYMEX | New York Mercantile Exchange |
NYSE | New York Stock Exchange |
OBPI | ONEOK Bushton Processing, L.L.C., formerly ONEOK Bushton Processing, Inc. |
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OCC | Oklahoma Corporation Commission |
ONEOK | ONEOK, Inc. |
ONEOK Credit Agreement | ONEOK’s $1.2 billion revolving credit agreement dated April 5, 2011 |
ONEOK Partners | ONEOK Partners, L.P. |
ONEOK Partners Credit Agreement | ONEOK Partners’ $1.2 billion revolving credit agreement dated August 1, 2011, as amended |
ONEOK Partners GP | ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole general partner of ONEOK Partners |
OPIS | Oil Price Information Service |
OSHA | Occupational Safety and Health Administration |
Overland Pass Pipeline Company | Overland Pass Pipeline Company LLC |
PHMSA | United States Department of Transportation Pipeline and Hazardous Materials Safety Administration |
POP | Percent of Proceeds |
Quarterly Report(s) | Quarterly Report(s) on Form 10-Q |
RRC | Railroad Commission of Texas |
S&P | Standard & Poor’s Rating Services |
SEC | Securities and Exchange Commission |
Securities Act | Securities Act of 1933, as amended |
VAR | Value-at-Risk |
Viking Gas Transmission | Viking Gas Transmission Company |
XBRL | eXtensible Business Reporting Language |
The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations and assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A, “Risk Factors,” and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation and “Forward-Looking Statements,” in this Annual Report.
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PART I
ITEM 1. BUSINESS
GENERAL
We are a diversified energy company and successor to the company founded in 1906 as Oklahoma Natural Gas Company. We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.” We are the sole general partner and own 43.4 percent of ONEOK Partners (NYSE: OKS), one of the largest publicly traded master limited partnerships. ONEOK Partners is a leader in the gathering, processing, storage and transportation of natural gas in the United States. In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers. We are the largest natural gas distributor in Oklahoma and Kansas and the third largest natural gas distributor in Texas, providing service as a regulated public utility to wholesale and retail customers. Our largest distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services business is engaged in providing premium natural gas marketing services to its customers across the United States. We apply our core capabilities of gathering, processing, fractionating, transporting, storing, marketing and distributing natural gas and NGLs through the rebundling of services across value chains, through vertical integration, in an effort to provide our customers with premium services at lower costs.
EXECUTIVE SUMMARY
In 2012, producers continued to drill aggressively in a number of crude oil and NGL-rich natural gas resource areas in the Mid-Continent and Rocky Mountain regions creating the need for additional natural gas gathering and processing and natural gas liquids infrastructure to bring this additional production to market. Natural gas prices were lower in 2012 caused by increased supply from drilling activities and decreased demand driven primarily by a warmer than normal winter, less natural gas price volatility and narrower natural gas location and seasonal price differentials in the markets we serve. NGL prices, particularly ethane and propane, also decreased in 2012 due primarily to increased NGL production from the development of NGL-rich areas. Propane prices also were affected by a warmer than normal winter.
We generally have seen strong ethane demand from the petrochemical sector in the Gulf Coast region due to the price advantage ethane has over other feedstocks. In 2011, natural gas liquids pipeline capacity between the Conway, Kansas, and Mont Belvieu, Texas, market centers was constrained and contributed to wider location price differentials between those markets. The natural gas supply growth during 2011 resulted in increased NGL supply in the Mid-Continent region, and when coupled with increased demand in the Gulf Coast region, resulted in lower NGL prices in the Mid-Continent market center at Conway, Kansas, relative to prices in the Gulf Coast market center at Mont Belvieu, Texas. During the second half of 2012, due to continued strong production growth from the development of NGL-rich areas, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers, NGL price differentials narrowed between the Mid-Continent and the Gulf Coast market centers. We expect the narrow NGL price differentials between these market centers to continue as new fractionators and pipelines, including our growth projects discussed below, continue to alleviate constraints affecting NGL prices and location price differentials between the two market centers. Over time, these growing fee-based NGL volumes are expected to fill much of the capacity used historically by ONEOK Partners to capture NGL price differentials between the two market centers.
The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential between ethane and natural gas, may influence the volume of ethane and propane available to be gathered from natural gas processing plants. When economic conditions warrant, natural gas processors may elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants. Price differentials between ethane and natural gas resulted in periods of ethane rejection in the Mid-Continent and Rocky Mountain regions during 2012. Ethane rejection did not have a material impact on our financial results. We expect lower natural gas liquids volumes in ONEOK Partners’ natural gas liquids business as a result of widespread and prolonged ethane rejection in 2013 that is expected to have a significant impact on our financial results. We do not expect prolonged ethane rejection to continue into 2014.
Despite lower commodity prices, North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from nonconventional resource areas such as shale areas. Producers receive currently higher market prices on a heating-value basis for crude oil and NGLs compared with natural gas. As a result, many producers focused their drilling activity in shale areas that produce crude oil and NGL-rich natural gas rather than areas with
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dry natural gas production. We expect continued demand for midstream infrastructure development driven by producers who need to connect emerging production with end-use markets where current infrastructure is insufficient or nonexistent.
Additional natural gas liquids fractionation and pipeline capacity is needed to accommodate the growing NGL supply and demand, as well as new infrastructure to gather, process and transport growing natural gas production from both new and existing resource areas. In response to this increased production and demand for NGL products, ONEOK Partners is investing approximately $4.7 billion to $5.3 billion in new capital projects to meet the needs of crude oil and natural gas producers in the Bakken Shale and Three Forks formations in the Williston Basin, Cana-Woodford Shale, Woodford Shale, Mississippian Lime and Granite Wash areas, and for additional natural gas liquids infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. When completed, ONEOK Partners expects these projects to provide additional earnings and cash flows.
During 2012, we paid cash dividends of $1.27 per share, an increase of approximately 18 percent from the $1.08 per share paid during 2011. In January 2013, we declared a dividend of $0.36 per share ($1.44 per share on an annualized basis), an increase of approximately 18 percent from the $0.305 declared in January 2012.
During 2012, ONEOK Partners paid cash distributions to its limited partners of $2.59 per unit, an increase of approximately 11 percent from the $2.325 per unit paid during 2011. In January 2013, ONEOK Partners GP declared a cash distribution to ONEOK Partners’ limited partners of $0.71 per unit ($2.84 per unit on an annualized basis), an increase of approximately 16 percent from the $0.61 declared in January 2012.
In January 2012, we completed an underwritten public offering of senior notes, generating net proceeds of approximately $694.3 million that were used to repay amounts outstanding under our $1.2 billion commercial paper program and for general corporate purposes.
During 2012, we relied primarily on operating cash flow, commercial paper and distributions from ONEOK Partners to fund our short-term liquidity and capital requirements, our purchase of 8.0 million common units from ONEOK Partners for approximately $460 million and our repurchase of approximately 3.4 million shares of our common stock for $150 million. In 2012, ONEOK Partners issued an additional 8.0 million common units and $1.3 billion of senior notes, generating net proceeds of approximately $1.7 billion. ONEOK Partners utilized proceeds from these equity and debt issuances, cash from operations and its commercial paper program to meet its short-term liquidity needs, repay maturing debt and to fund its capital projects.
In June 2012, we completed a two-for-one split of our common stock. We have adjusted all share and per-share amounts contained herein to be presented on a post-split basis.
On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized an after-tax gain on the sale of approximately $13.5 million. The proceeds from the sale were used to reduce short-term borrowings. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report. All prior periods presented have been recast to reflect the discontinued operations.
We anticipate that our cash flow generated from operations, existing capital resources and distributions from ONEOK Partners will enable us to maintain our current and planned levels of operations and provide us flexibility should we elect to execute on any portion of the $300 million remainder of our three-year, $750 million stock repurchase program. ONEOK Partners anticipates that its cash flow generated from operations, existing capital resources and ability to obtain financing will enable it to maintain its current and planned levels of operations. Additionally, ONEOK Partners expects to fund its capital expenditures with proceeds from short- and long-term debt, the issuance of equity and operating cash flows.
See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, for more information on our growth projects, results of operations, liquidity and capital resources.
BUSINESS STRATEGY
Our primary business strategy is to deliver consistent growth and sustainable earnings, while focusing on safe, reliable and environmentally responsible operations for our customers, employees, contractors and the public through the following:
• | Operate in a safe, reliable and environmentally responsible manner - environmental, safety and health issues continue to be a primary focus for us; our emphasis on personal and process safety has produced improvements in |
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the key indicators we track. We also continue to look for ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies;
• | Generate consistent growth and sustainable earnings - during 2012, ONEOK Partners’ cash distributions increased by 26.5 cents per unit, an increase of approximately 11 percent compared with 2011; ONEOK Partners is investing approximately $4.7 billion to $5.3 billion in new capital projects to meet the needs of crude oil, NGL and natural gas producers in the Williston Basin, Cana-Woodford Shale, Woodford Shale, Mississippian Lime and Granite Wash areas, and for additional natural gas liquids infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. When completed, these projects are anticipated to provide additional earnings and cash flows. Our Natural Gas Distribution segment benefits from rate strategies, including a performance-based rate mechanism in Oklahoma, capital-recovery mechanisms in Kansas and portions of Texas and cost-of-service adjustments in certain Texas jurisdictions that address investments in rate base and changes in expense; our Natural Gas Distribution segment’s operating efficiencies include investments in automated meter-reading devices. Our Energy Services segment is taking steps to realign fixed costs with its current business environment, including attempts to renegotiate various storage and transportation agreements and continuing to realign its contracted storage and transportation capacity with its customers’ premium-services requirements; |
• | Execute strategic acquisitions that provide long-term value - we remain disciplined in our approach and continue to evaluate assets that come to market. We did not consummate any acquisitions in 2012; |
• | Manage our balance sheet to maintain strong credit ratings at or above current levels - our balance sheet remains strong, and we will seek to maintain our investment-grade credit ratings; and |
• | Attract, select, develop and retain employees to support strategy execution - we continue to execute on our recruiting strategy that targets colleges, universities and vocational-technical schools in our operating areas. We also continue development efforts with our current employees. |
NARRATIVE DESCRIPTION OF BUSINESS
We report operations in the following business segments:
• | ONEOK Partners; |
• | Natural Gas Distribution; and |
• | Energy Services. |
ONEOK Partners
Overview - ONEOK Partners is a diversified master limited partnership involved in the gathering, processing, storage and transportation of natural gas in the United States. In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.
We own approximately 92.8 million common and Class B limited partner units, and the entire 2-percent general partner interest, which, together, represent a 43.4-percent ownership interest in ONEOK Partners. We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. See Note P of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our incentive distribution rights.
We and ONEOK Partners maintain significant financial and corporate governance separations. We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of ONEOK Partners’ businesses individually. To aid in understanding the important business and financial characteristics of our ONEOK Partners segment, the following describes its business with reference to its underlying activities.
Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business provides nondiscretionary services to producers that include gathering and processing of natural gas produced from crude oil and natural gas wells. ONEOK Partners gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, Woodford Shale and Granite Wash areas; the Mississippian Lime area of Oklahoma and Kansas; and the Hugoton and Central Kansas Uplift Basins of Kansas. It also gathers and/or processes natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks areas; and the Powder River Basin of Wyoming. In the Powder River Basin, the natural gas that ONEOK Partners gathers is coal-bed methane, or dry natural gas that does not require processing or
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NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.
In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue natural gas. The residue natural gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are in the form of a mixed, unfractionated NGL stream. ONEOK Partners’ natural gas and NGLs are sold to its affiliates and a diverse customer base.
Revenue from the natural gas gathering and processing business is derived primarily from the following three types of contracts:
• | POP - ONEOK Partners retains a percentage of the NGLs and/or a percentage of the residue gas as payment for gathering, treating, compressing and processing the producer’s natural gas. This type of contract represented approximately 41 percent and 37 percent of gathering and processing contracted volumes for 2012 and 2011, respectively. |
• | Fee - ONEOK Partners is paid a fee for the services it provides based on Btus gathered, treated, compressed and/or processed. This type of contract represented approximately 57 percent and 60 percent of gathering and processing contracted volumes for 2012 and 2011, respectively. |
• | Keep-whole - ONEOK Partners extracts NGLs from unprocessed natural gas and returns to the producer volumes of residue natural gas containing the same amount of Btus as the unprocessed natural gas that was originally delivered. This type of contract represented approximately 2 percent and 3 percent of gathering and processing contracted volumes for 2012 and 2011, respectively. Approximately 78 percent and 75 percent of ONEOK Partners’ volume under keep-whole contracts for 2012 and 2011, respectively, contain terms that effectively convert these contracts into fee contracts when the gross processing spread is negative. |
Natural gas pipelines business - ONEOK Partners’ natural gas pipeline business owns and operates regulated natural gas transmission pipelines and natural gas storage facilities. ONEOK Partners also provides interstate natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act.
ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.
ONEOK Partners’ revenues from its natural gas pipelines are derived typically from fee-based services provided to its customers. Its revenues are generated from the following types of fee-based contracts:
• | Firm service - Customers can reserve a fixed quantity of pipeline or storage capacity for the terms of their contract. Under this type of contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage. The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store, and/or we may retain a specified volume of natural gas in-kind for fuel. Under the firm-service contract, the customer generally is guaranteed access to the capacity they reserve; and |
• | Interruptible service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm-service requests are satisfied or on an as-available basis. Interruptible service customers typically are assessed fees, such as a commodity charge, based on their actual usage, and/or we may retain a specified volume of natural gas in-kind for fuel. Under the interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess capacity is available. |
Natural gas liquids business - ONEOK Partners’ natural gas liquids business gathers, treats, fractionates, stores and transports NGLs and distributes and stores NGL products. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas, as well as to third-party fractionators and pipelines. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to ONEOK Partners’ customers, such as petrochemical manufacturers, heating-fuel users, refineries and propane distributors, through ONEOK Partners’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the Mid-Continent and Gulf Coast NGL market centers, as well as the Midwest markets near Chicago, Illinois.
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Revenues from the natural gas liquids business are derived primarily from nondiscretionary fee-based services provided to ONEOK Partners’ customers and physical optimization of its natural gas liquids assets. Its fee-based services have increased due primarily to previously completed capital projects, including the Cana-Woodford Shale and Granite Wash projects and expansion of its fractionation capacity. The sources of revenue are categorized as follows:
• | Exchange services’ activities - ONEOK Partners primarily gathers, fractionates and treats unfractionated NGLs for a fee, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments. |
• | Optimization and marketing activities - ONEOK Partners utilizes its assets, contract portfolio and market knowledge to capture location and seasonal price differentials. ONEOK Partners transports NGL products between the Mid-Continent and Gulf Coast in order to capture the location price differentials between the two market centers. ONEOK Partners’ natural gas liquids storage facilities are also utilized to capture seasonal price variances. A growing portion of its marketing activities serves truck and rail markets. |
• | Pipeline transportation business - ONEOK Partners transports unfractionated NGLs, NGL products and refined petroleum products primarily under our FERC-regulated tariffs. Tariffs specify the maximum rates ONEOK Partners charges its customers and the general terms and conditions for NGL transportation service on its pipelines. |
• | Isomerization activities - ONEOK Partners captures the price differential when normal butane is converted into the more valuable iso-butane at its isomerization unit in Conway, Kansas. Iso-butane is used in the refining industry to increase the octane of motor gasoline. |
• | Storage services - ONEOK Partners stores NGLs at its Mid-Continent and Gulf Coast facilities for a fee. |
Market Conditions and Seasonality - Supply - Natural gas and NGL supply is affected by producer drilling activity, which is sensitive to commodity prices, drilling rig availability, exploration success, operating capability, the NGL content of the natural gas that is produced and processed, access to capital and regulatory control. Crude oil prices and advances in horizontal drilling and completion technology have had a positive impact on drilling activity in the crude oil and NGL-rich shale and other nonconventional resource areas, providing an offset to the less favorable supply projections in some of the dry natural gas conventional resource areas.
In the Rocky Mountain region, Williston Basin volumes continue to grow as well connections from drilling completions increase, driven primarily by producer development of Bakken Shale and Three Forks formation crude-oil wells, which also produce associated natural gas containing significant quantities of NGLs. However, ONEOK Partners’ natural gas gathering and processing business has experienced declines in natural gas volumes gathered in the Powder River Basin, which produces dry natural gas.
In the Mid-Continent region, ONEOK Partners expects increased drilling activity in the Cana-Woodford Shale and Granite Wash areas of western Oklahoma and the Mississippian Lime area of Oklahoma and Kansas to more than offset the volumetric declines in most conventional wells that supply ONEOK Partners’ natural gas gathering and processing facilities and intrastate natural gas pipelines and storage assets.
ONEOK Partners’ interstate natural gas pipelines access supply from major producing regions in the Mid-Continent, Rocky Mountain, Gulf Coast and Canada.
ONEOK Partners expects the overall supply of NGLs to continue to increase, as well as demand for its fee-based services, as a result of the development of shale areas and other nonconventional resource areas. Many new natural gas processing plants are being constructed in Oklahoma and the Texas Panhandle to process NGL-rich natural gas being produced in the Cana-Woodford Shale, Granite Wash, Woodford Shale and Mississippian Lime areas. ONEOK Partners’ natural gas liquids gathering and fractionation operations receive NGLs from a variety of processors and pipelines, including affiliates, located in these regions.
ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses also are affected by operational or market-driven changes that impact the output of natural gas processing plants. The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential between ethane and natural gas, may influence the volume of NGLs available to be gathered from natural gas processing plants. During 2012, the value of ethane was periodically below that of natural gas, which negatively impacted the economic incentive for ethane recovery and caused some natural gas processing plants that deliver NGLs to our natural gas liquids gathering pipelines to reduce ethane production. There are a variety of factors that affect whether a processing plant will reduce or reject ethane production; however, we expect periods of low ethane prices relative to natural gas, causing periods of lower ethane production during 2013. ONEOK Partners’
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natural gas processing plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing operating parameters at certain plants, ONEOK Partners can reduce, to some extent, the amount of ethane and propane recovered in its processing plants if prices or processing margins are unfavorable. During 2012, ethane rejection did not have a material impact on our financial results. We expect lower natural gas liquids volumes in ONEOK Partners’ natural gas liquids business as a result of widespread and prolonged ethane rejection in 2013 that is expected to have a significant impact on our financial results. We do not expect prolonged ethane rejection to continue into 2014.
Natural gas and/or natural gas liquids pipeline capacity constraints may also impact the output of natural gas processing plants in total or for specific NGL products in the future. During 2012, we experienced limited reductions of supply related to changes in plant output as a result of pipeline capacity constraints.
Demand - Demand for natural gas gathering and processing services is aligned typically with the production of natural gas from natural gas resource areas or the associated natural gas from wells drilled in crude oil resource areas. Gathering and processing are nondiscretionary services that producers require to market their natural gas and NGL production. As producers continue to develop shale and other resource areas, ONEOK Partners expects demand for its natural gas gathering and processing services to increase.
Demand for natural gas pipeline transportation service and natural gas storage is related directly to demand for natural gas in the markets that ONEOK Partners’ natural gas pipelines and storage facilities serve, and is affected by weather, the economy and natural gas and NGL price volatility. ONEOK Partners’ natural gas pipelines primarily serve end-users, such as local natural gas distribution companies, electric-generation companies, large industrial companies, municipalities and irrigation customers that require natural gas to operate their businesses and generally are not impacted by location price differentials. However, narrower location price differentials may impact demand for ONEOK Partners’ services from natural gas marketers as discussed below under “Commodity Prices.” Demand for ONEOK Partners’ natural gas pipelines services can also be impacted as coal-fired electric generators consider natural gas as an alternative fuel.
The strength of the economy directly impacts manufacturing and industrial companies that consume natural gas. Commodity price volatility can influence producers’ decisions related to the production of natural gas, the level of NGLs processed from natural gas, and natural gas storage injection and withdrawal activity.
Demand for NGLs and the ability of natural gas processors to sustain successfully and economically their operations impacts the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, fractionation and distribution services. Natural gas and propane are subject to weather-related seasonal demand. Other NGL products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as butanes and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane, propane, normal butane and natural gasoline are used by the petrochemical industry to produce chemical products, such as plastics, rubber and synthetic fibers. Several petrochemical companies announced or completed new plants, plant expansions, additions or enhancements that improve the light-NGL feed capability of their facilities due primarily to the increased supply and attractive price of ethane as a petrochemical feedstock in the United States. As these projects are completed over the next five years, we expect ethane demand to increase. The demand is expected to increase significantly in three to five years when the new petrochemical plants are completed. In addition, international demand for propane is expected to impact positively the NGL market in the future. ONEOK Partners expects this increase in demand for NGLs will provide opportunities for its natural gas liquids exchange services activities to add incremental fee-based earnings.
Commodity Prices - Crude oil, natural gas and NGL prices can be volatile due to changes in market conditions. Commodity prices can also be impacted by demand for products from the petrochemical industry and other consumers, storage injection and withdrawal rates and available storage capacity. The increase in natural gas supply from shale gas development has caused natural gas prices to decline and natural gas location and seasonal price differentials to narrow across most of the regions where ONEOK Partners operates. However, an increase in crude oil prices and the abundance of NGLs produced from the development of NGL-rich shale resource areas have made producing NGL feedstocks for the petrochemical industry more profitable. ONEOK Partners is exposed to commodity price risk in its natural gas gathering and processing business, as a result of receiving commodities in exchange for services, primarily on POP contracts, and in its natural gas liquids business from the NGLs it purchases and sells.
ONEOK Partners is also exposed to market risk associated with the price differentials between receipt and delivery points along its natural gas and natural gas liquids pipelines, also known as location differentials. Fluctuations in location differentials impact the rates its natural gas pipelines’ customers with competitive alternatives are willing to pay and the optimization opportunities for its natural gas liquids business. During the second half of 2012, due to strong production and supply growth
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from the development of NGL-rich shale areas, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers, NGL price differentials narrowed between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas. ONEOK Partners’ natural gas and NGL storage revenues are impacted by the differential between the forward price of natural gas and NGLs and the price of natural gas and NGLs on the spot market. Additionally, fluctuations in the relative price differential between natural gas, NGLs and individual NGL products impacts ONEOK Partners’ natural gas liquids exchange services and transportation revenues and, to a lesser extent, margins on its natural gas gathering and processing keep-whole contracts.
To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, ONEOK Partners uses commodity derivative instruments such as futures, swaps and physical-forward contracts to manage commodity-price risk associated with existing or anticipated purchase and sale agreements, existing physical natural gas or natural gas liquids in storage and location price differentials.
Seasonality - Our ONEOK Partners segment’s products are subject to weather-related seasonal demand. Cold temperatures typically increase demand for natural gas and propane, which are used to heat homes and businesses. Warm temperatures typically drive demand for natural gas used for natural gas-fired electric generation needed to meet the electricity-generation demand required to cool residential and commercial properties. Precipitation levels also can impact the demand for natural gas that is used to fuel irrigation activity in the Mid-Continent region and demand for propane used to fuel crop-drying activity. Demand for butane and natural gasoline, which are used primarily by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, may also be subject to some variability as automotive travel increases and as seasonal gasoline formulation standards are implemented. During periods of peak demand for a certain commodity, prices for that product typically increase, which may influence natural gas processing and NGL fractionation decisions.
Competition - ONEOK Partners’ natural gas and natural gas liquids businesses compete directly with other companies for natural gas and NGL supply, markets and services. Competition for natural gas transportation services continues to increase as new infrastructure projects are completed and the FERC and state regulatory bodies continue to encourage additional competition in the natural gas markets. Competition is based primarily on fees for services, quality of services provided, current and forward natural gas and NGL prices and proximity to supply areas and markets. ONEOK Partners believes that the location and integration of its assets enable it to compete effectively.
ONEOK Partners’ natural gas gathering and processing business competes for natural gas supplies with independent exploration and production companies that have gathering and processing assets, pipeline companies and their affiliated marketing companies, national and local natural gas gatherers and processors, and marketers in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ natural gas liquids business competes with other fractionators, intrastate and interstate pipeline companies, storage providers, gatherers and transporters for NGL supplies in the Rocky Mountain, Mid-Continent and Gulf Coast regions. The factors that typically affect ONEOK Partners’ ability to compete for natural gas and NGL supply are:
• | quality of services provided; |
• | producer drilling activity; |
• | the petrochemical industry’s level of capacity utilization and feedstock requirements; |
• | fees charged under its contracts; |
• | current and forward NGL prices; |
• | location of its assets relative to those of its competitors; |
• | location of its assets relative to drilling activity; |
• | proximity to NGL supply areas and markets; |
• | efficiency and reliability of its operations; |
• | pressures maintained on its gathering systems; and |
• | receipt and delivery capabilities that exist for natural gas and NGLs in each pipeline system, processing plant, fractionator and storage location. |
ONEOK Partners is responding to these factors by making capital investments to access new supply; increasing gathering, fractionation and distribution capacity; increasing storage, withdrawal and injection capabilities; and improving natural gas processing efficiency and reducing operating costs. ONEOK Partners’ competitors have also recently announced plans for, and in some cases are already constructing or have completed, new natural gas gathering and processing facilities and natural gas liquids pipelines and fractionators to address the growing natural gas and NGL supply and petrochemical demand. ONEOK Partners is also evaluating opportunities to maximize earnings and renegotiating low-margin contracts with the principal goals of improving margins and reducing risk. When completed, ONEOK Partners’ growth projects and those of its competitors are expected to impact NGL prices and narrow location price differentials between the Mid-Continent and Gulf Coast market
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centers. We believe ONEOK Partners’ natural gas gathering and processing, NGL fractionation, pipelines and storage assets are located strategically, connecting diverse supply areas to market centers.
Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of ONEOK Partners’ natural gas processing operations or facilities, ONEOK Partners’ natural gas processing plants are primarily involved in extracting NGLs and, therefore, ONEOK Partners believes its natural gas processing plants are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. ONEOK Partners believes its natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional gathering facility status. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has distinguished historically between these two types of facilities, either interstate or intrastate, on a fact-specific basis. ONEOK Partners also transports residue gas from its natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.
Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, in various degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.
ONEOK Partners’ interstate natural gas pipelines are regulated under the Natural Gas Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually all aspects of the pipeline activities. ONEOK Partners’ intrastate natural gas transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. ONEOK Partners has flexibility in establishing natural gas transportation rates with customers. However, there are maximum rates that ONEOK Partners can charge its customers in Oklahoma and Kansas.
The operations and revenues of ONEOK Partners’ natural gas liquids pipelines are regulated by various state and federal government agencies. Its interstate natural gas liquids pipelines are regulated by the FERC, which has authority over the terms and conditions of service, rates, including depreciation and amortization policies and initiation of service. In Oklahoma, Kansas and Texas, ONEOK Partners’ intrastate natural gas liquids pipelines that provide common carrier service are subject to the jurisdiction of the OCC, KCC and RRC, respectively.
PHMSA has asserted jurisdiction over certain portions of ONEOK Partners’ natural gas liquids fractionation facilities in Bushton, Kansas, that ONEOK Partners believes are not subject to its jurisdiction. ONEOK Partners has objected to the scope of PHMSA’s jurisdiction and is seeking resolution of this matter. We do not anticipate that the cost of compliance will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
See further discussion in the “Environmental and Safety Matters” section.
Unconsolidated Affiliates - Our ONEOK Partners segment has investments in unconsolidated affiliates that include Northern Border Pipeline, Overland Pass Pipeline Company, three partnerships that operate natural gas gathering systems located primarily in the Powder River of Wyoming and other investments. Northern Border Pipeline is a leading transporter of natural gas imported from Canada into the United States. Overland Pass Pipeline Company operates an interstate natural gas liquids pipeline system that transports natural gas liquids from the Rocky Mountain region to the Mid-Continent NGL market center.
See Note O of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of ONEOK Partners’ unconsolidated affiliates.
Natural Gas Distribution
Overview - Our Natural Gas Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our LDCs serve wholesale and public authority customers. We operate subject to regulations and oversight of the state regulatory agencies. Our regulatory strategy incorporates features that reduce earnings lag, protect margin and mitigate risks.
Our strategies to reduce earnings lag include a performance-based rate mechanism in Oklahoma and capital-recovery mechanisms in Kansas and portions of Texas. In addition, we also have cost-of-service adjustments in certain Texas markets that address investments in rate base and changes in operating expenses.
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Margin protection strategies include increasing the portion of our service fees that is fixed rather than volumetrically based. Customer consumption is affected by end-use equipment efficiency, natural gas prices and weather conditions. Weather normalization mechanisms in place in Oklahoma, Kansas and portions of Texas are designed to limit our sensitivity to weather.
Risk mitigation strategies include mechanisms to recover the fuel-related component of bad debts in all three states, pension and other postretirement benefits in Kansas and portions of Texas, and ad valorem taxes in Kansas.
Our operating results are affected primarily by the number of customers, usage and the ability to collect service fees that provide a reasonable rate of return on our investment and recovery of our cost of service. Natural gas costs are passed through to our customers based on the actual cost of natural gas purchased by the respective natural gas distribution company and related expenses, including transportation and storage costs. Substantial fluctuations in natural gas sales can occur from year to year without materially or adversely impacting our net margin, since the fluctuations in natural gas costs affect natural gas sales and cost of gas by an equivalent amount. Higher natural gas costs may cause customers to conserve or use alternative energy sources. Higher natural gas costs may also impact adversely our accounts receivable collections, resulting in higher bad-debt expense.
Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as public utilities to approximately 87 percent, 70 percent and 14 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively. Natural gas sold to residential and commercial customers as a percentage of our LDC’s total natural gas sales by state is presented in the table below:
Oklahoma | Kansas | Texas | |
Residential | 83% | 79% | 70% |
Commercial | 17% | 19% | 22% |
Market Conditions and Seasonality - Supply - Our LDCs purchased 140 Bcf and 163 Bcf of natural gas supply in 2012 and 2011, respectively. Our natural gas supply portfolio consists of long-term, seasonal and short-term contracts from a diverse group of suppliers. These contracts are awarded through competitive-bidding processes to ensure reliable and competitively priced natural gas supply. Our Natural Gas Distribution segment’s natural gas supply is acquired from natural gas processing plants, natural gas marketers and natural gas producers.
An objective of our supply-sourcing strategy is to provide value to customers through reliable, competitively priced and flexible natural gas supply and transportation purchases from multiple production areas and suppliers. This strategy is designed to prevent supply from being curtailed by physical interruption, possible financial difficulties of a single supplier, natural disasters and other unforeseen force majeure events, as well as ensuring these resources are reliable and flexible to meet the variations of customer demands.
We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were to occur, each of our LDCs has curtailment tariff provisions in place that provide for: reducing or discontinuing natural gas service to large industrial users; and requesting that residential and commercial customers reduce their natural gas requirements to an amount essential for public health and safety. In addition, during times of critical supply disruptions, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal, state and local regulatory agencies.
Natural gas supply requirements are affected by weather conditions. In addition, economic conditions impact the requirements of our commercial and industrial customers. Natural gas usage per residential customer may decline as customers change their consumption patterns in response to: (i) more volatile and higher natural gas prices, as discussed above; (ii) customers’ improving the energy efficiency of existing homes by replacing doors and windows and adding insulation, and replacing appliances with more efficient appliances; (iii) more energy-efficient construction; and (iv) fuel switching. In each jurisdiction in which we operate, changes in customer-usage profiles are considered in the periodic redesign of our rates.
In managing our natural gas supply portfolios, we partially mitigate price volatility using a combination of physical and financial derivatives and natural gas in storage. We have natural gas hedging programs that have been authorized by the regulatory authorities in each state in which our LDCs do business. We do not utilize financial derivatives for speculative purposes nor do we have trading operations associated with our Natural Gas Distribution segment. We utilized 39.3 Bcf of contracted storage capacity in 2012, which allows natural gas to be purchased during the off-peak season and stored for use in the winter periods.
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Demand - See discussion below under “Seasonality” and “Competition” for factors affecting demand for our services.
Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas requirements are for heating. Accordingly, the volume of natural gas sales is higher normally during the months of November through March than in other months of the year. The impact on margins for our LDCs resulting from weather that is above or below normal is offset in part through weather-normalization adjustments (WNA). These adjustments have been approved by the regulatory authorities for our Oklahoma, Kansas and certain Texas service territories. WNA allow us to increase customer billing to offset lower gas usage when weather is warmer than normal and decrease customer billing to offset higher gas usage when weather is colder than normal.
Competition - We encounter competition based on customers’ preference for natural gas, compared with other energy products and their comparative prices. The most significant product competition occurs between natural gas and electricity in the residential and small commercial markets. We compete for space and water heating, cooking, clothes drying and other general energy needs. Customers and builders typically make the decision on the type of equipment at initial installation and use the chosen energy source for the life of the equipment. The markets in our service territories have become increasingly competitive. Changes in the competitive position of natural gas relative to electricity and other energy products have the potential to cause a decline in consumption or in the number of natural gas customers.
However, industry studies have demonstrated that assessing energy efficiency in terms of full fuel-cycle analysis highlights the high overall efficiency of natural gas in residential and commercial uses, compared with electricity. The Department of Energy issued a statement of policy that it will use full fuel-cycle measures of energy use and emissions when evaluating energy-conservation standards for appliances. Further, independent studies show that natural gas provides a cost advantage over electricity for typical home and business applications.
We believe that we must maintain a competitive advantage in order to retain our customers, and, accordingly, we focus on providing safe, reliable and efficient service and controlling costs. Our Natural Gas Distribution segment is subject to competition from other pipelines for our existing industrial load. Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service compete for service to large industrial and commercial customers, and competition has and may continue to impact margins.
Under our transportation tariffs, qualifying industrial and commercial customers are able to purchase their natural gas commodity from the supplier of their choice and have us transport it for a fee. A portion of transportation services provided is at negotiated rates that are generally below the maximum approved transportation tariff rates. Reduced rate transportation service may be negotiated when a competitive pipeline is in proximity or another viable energy option is available. Increased competition could potentially lower these rates.
Government Regulation - Rates charged for natural gas transportation services by the LDCs in our Natural Gas Distribution segment are established by the OCC for Oklahoma Natural Gas and by the KCC for Kansas Gas Service. Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Rates in unincorporated areas of Texas and all appellate matters are subject to regulatory oversight by the RRC. Natural gas supply costs for our LDCs are passed on to our customers through a purchased-gas cost-adjustment mechanism. We do not make a profit on the cost of natural gas. Other changes in costs must be recovered through periodic rate adjustments approved by the OCC, KCC, RRC and various municipalities in Texas. See page 56 for a detailed description of our various regulatory initiatives.
See further discussion in the “Environmental and Safety Matters” section.
Energy Services
Overview - Our Energy Services segment is a provider of natural gas supply and risk-management services for natural gas and electric utilities and commercial and industrial customers. We use a network of leased storage and transportation capacity to supply natural gas to our customers. This network connects the major supply and demand centers throughout the United States and into Canada and, coupled with our industry knowledge and market intelligence, allows us to provide our customers with customized services in a more efficient and reliable manner than they can achieve independently.
Strategy - We follow a strategy of optimizing our storage and cross-regional transportation capacity through the application of market knowledge and effective risk management. We seek to maximize value by actively hedging the risks associated with seasonal and location price differentials that are inherent to storage and transportation contracts. At the same time, we attempt to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market
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inefficiencies, which allow us to capture additional margin. Using market information, we manage these asset-based positions and seek to provide incremental margin in our trading portfolio.
To ensure natural gas is available when our customers need it, we offer premium services and products that satisfy our customers’ nonuniform supply needs such as swing and peaking natural gas load requirements on a year-round basis. Types of premium services include next-day and no-notice services. Next-day services allow our customers to call on additional gas supply up to an amount agreed upon in a service contract and expect delivery the following day. No-notice services allow customers to call on additional gas supply and expect immediate delivery. We also provide weather-related protection and other custom solutions based on our customers’ specific needs. Our storage and transportation assets enable us to provide these services and provide us with opportunities to capture daily, monthly and seasonal value due to market inefficiencies.
As a result of significant increases in the supply of natural gas, primarily from shale production across North America, location and seasonal natural gas price differentials have narrowed significantly, resulting in reduced opportunities to capture margins with our firm transportation and storage capacity. Additionally, price volatility in the natural gas markets remains relatively low compared with volatility in the past, which, coupled with a fairly flat forward price curve, reduces the value of the demand fee we receive for premium services and further limits opportunities to optimize our assets. We have undertaken several steps to better align fixed costs with the current business environment, including allowing nonstrategic contracts to expire and attempting to renegotiate various natural gas storage and transportation contracts. Contract renegotiation activities that we have taken or expect to take include renewing contracts at current market prices at contract expiration, extending contracts in order to negotiate a more favorable rate or paying to terminate contracts in areas that are no longer strategic to our business. It is possible that we may recognize charges to our earnings as a result of certain of these actions. We expect these contractual changes to result in less storage and transportation capacity under lease and a better alignment of our contracted natural gas transportation and storage capacity with the needs of our premium-services customers. We also expect the reduction in our contracted natural gas transportation and storage capacity will reduce our operating costs and working-capital requirements.
Approximately 311.1 MMcf/d, or 32 percent, of our transportation capacity expires by the end of 2013, and an additional 390.4 MMcf/d, or 41 percent, of our transportation capacity expires by the end of 2015. Approximately 22.3 Bcf, or 31 percent, of our storage capacity expires by the end of 2013, and an additional 40.5 Bcf, or 57 percent, of our storage capacity expires by the end of 2015. Our strategy is to either release this capacity or recontract at market rates.
Derivatives - We intend to minimize the mark-to-market earnings impact that our forward hedges have on current period earnings. When possible, we implement hedging strategies using derivative instruments that qualify as hedges for accounting purposes. We actively manage the commodity price and volatility risks associated with providing energy risk-management services to our customers by executing derivative instruments in accordance with the parameters established in our risk-management and compliance policy. The derivative instruments consist of over-the-counter transactions such as forward, swap and option contracts, and NYMEX futures and option contracts.
We utilize our experience to optimize the value of our contracted assets and use our risk management and marketing capabilities to manage risk and generate additional margins. We apply a combination of cash flow and fair value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions. See Note D of the Notes to Consolidated Financial Statements in this Annual Report for additional information. Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions such as certain of our storage and transportation contracts, will not qualify for hedge accounting treatment. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship. As a result, the underlying risk being hedged receives accrual accounting treatment, while we use mark-to-market accounting treatment for the economic hedges. We cannot predict the earnings fluctuations from mark-to-market accounting, and the impact on earnings could be material.
In prior years, we were able to hedge location price differentials and seasonal storage price differentials at more favorable levels compared with opportunities currently available to us. These factors have impacted negatively our Energy Services segment’s results of operations in 2011 and 2012, and we anticipate these factors will persist throughout 2013. A significant amount of our storage and transportation hedges that were entered into at favorable levels were realized by the end of 2011.
Working Capital - Our Energy Services segment requires working capital to purchase natural gas inventory, to reserve transportation and storage capacity and to meet cash collateral requirements associated with our risk-management activities. Our inventory purchases and hedging strategies are implemented with consideration given to ONEOK’s overall working capital requirements and liquidity. Restrictions on our access to working capital may impact our inventory purchases and risk-management activities, which could impact our results. Our working capital costs would be impacted by a change in ONEOK’s current investment-grade credit ratings or a significant increase in commodity prices. See discussion under “Credit Risk” of
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Note D of the Notes to Consolidated Financial Statements in this Annual Report for additional information about the impact of a change in ONEOK’s credit rating.
Our working capital requirements related to our inventory in storage were as high as $202.3 million during 2012 and had decreased to $169.1 million by December 31, 2012. In addition, margin requirements can result in increased working capital requirements. During 2012, the amount we were required to post with counterparties to meet our margin requirements ranged from zero to $31.4 million, and the amount posted for our benefit by our counterparties ranged from zero to $69.7 million.
Sales with Affiliates - Our Energy Services segment conducts business with our ONEOK Partners and Natural Gas Distribution segments. These services are provided under agreements with market-based terms. Additionally, business with our LDCs is awarded through a competitive-bidding process.
Market Conditions and Seasonality - Supply - Our Energy Services segment maintains a natural gas supply portfolio consisting of various term-length contracted supply in all of the major producing regions, including the Rocky Mountain, Mid-Continent and Gulf Coast. During periods of high natural gas demand, we utilize storage capacity that allows us to supplement natural gas supply volumes to meet our peak-day demand obligations or market needs.
An increase in shale natural gas production and related pipeline construction across North America has resulted in greater natural gas supply, putting downward pressure on natural gas prices and narrowing the price differentials between regions. The impact of lower natural gas prices and price volatility and narrower location and seasonal price differentials has resulted in reduced opportunities to capture incremental margin through optimization efforts.
Demand - Demand under our swing and peaking natural gas requirements contracts in our wholesale operation usually is driven by the extent to which temperatures vary from normal levels. A significant portion of this business is contracted during the winter period of November through March.
The displacement of electric power-generation plants from coal to natural gas is resulting in a moderate increase in demand for natural gas. These displacements are being driven by the lower cost of natural gas relative to coal and to a lesser extent due to potential government regulations.
Customers continue to contract for storage, transportation and premium services but at lower prices due to lower natural gas prices resulting from the increased supply and lower natural gas price volatility. Although future improvements in the U.S. economy, coupled with the depressed natural gas price environment, could increase modestly customer demand, we do not anticipate a significant change in customer demand in 2013.
Seasonality - Due to the seasonality of natural gas consumption, storage withdrawals and demand for our products and services, earnings are higher normally during the winter months than the summer months. Natural gas sales volumes are higher typically in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices.
Increased natural gas supply is also impacting negatively the seasonal price differentials. There could be situations where winter prices are lower, due to mild weather and abundant supply, than the prices in the upcoming summer. These changes could result in unfavorable pricing between periods that could result in losses on the withdrawal of natural gas from inventory.
Competition - In response to a challenging marketing environment, our strategy is to concentrate our efforts on providing reliable service during peak-demand periods. We can compete effectively in the market by utilizing our contracted storage and transportation assets. We continue to focus on building and strengthening supplier and customer relationships to execute our strategy and increase our market presence.
Government Regulation - Our Energy Services segment purchases natural gas for resale at negotiated rates in interstate commerce. As such, it has been granted by FERC an automatic blanket certificate of public convenience and necessity authorizing such sales. This is a limited certificate that does not subject our Energy Services segment to any other regulation of FERC under its Natural Gas Act jurisdiction. Holders of blanket marketing certificates are subject to certain reporting and document retention requirements.
Market conditions and uncertainties associated with the implementation of financial reform through the Dodd-Frank Act have reduced liquidity in the financial derivatives markets, particularly for basis swaps, which make it difficult to implement forward hedges around our transportation and storage positions. See “Financial Markets Legislation” for discussion of the Dodd-Frank Act.
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SEGMENT FINANCIAL INFORMATION
Operating Income, Customers and Total Assets - See Note R of the Notes to Consolidated Financial Statements in this Annual Report for disclosure by segment of our operating income and total assets and for a discussion of revenues from external customers.
Other
Through ONEOK Leasing Company, L.L.C., and ONEOK Parking Company, L.L.C., we own a parking garage and an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, where our headquarters are located. ONEOK Leasing Company, L.L.C., leases excess office space to others and operates our headquarters office building. ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters.
FINANCIAL MARKETS LEGISLATION
The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act. The CFTC has issued final regulations for many provisions of the Dodd-Frank Act that have varying effective dates for compliance, but others remain outstanding. Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the capital requirements and costs of hedging may increase as a result of the regulations. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material. These requirements could affect adversely market liquidity and pricing of derivative contracts, making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
ENVIRONMENTAL AND SAFETY MATTERS
Additional information about our environmental matters is included in Note Q of the Notes to Consolidated Financial Statements in this Annual Report.
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and/or regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The new law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to the following:
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• | an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas; |
• | a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions; |
• | a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and |
• | a requirement to test previously untested pipelines operating above 30-percent yield strength in high-consequence areas. |
The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.
Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations promulgated thereunder, impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air-pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.
Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are under way. We monitor all relevant federal and state legislation to assess the potential impact on our operations. In 2009, the EPA released its Mandatory Greenhouse Gas Reporting Rule, which requires annual greenhouse gas emissions reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us to our distribution customers who are not otherwise required to report their own emissions and the emission equivalents for all NGLs produced by ONEOK Partners as if all of these products were combusted, even if they are used otherwise. Also, the EPA released a subpart to the Mandatory Greenhouse Gas Reporting Rule that requires the annual reporting of vented and fugitive emissions of methane from certain facilities beginning with the reporting of 2011 fugitive emission in 2012. Our 2011 total reported emissions were approximately 64.8 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers and produced, as if all such fuel and NGL products were combusted. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.
In May 2010, the EPA finalized the “Tailoring Rule” that regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and at current emission threshold levels has not had a material impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.
In 2010, the EPA issued a rule on air-quality standards titled, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, which initially included a compliance date in 2013. Subsequent industry appeals and settlements with the EPA have extended timelines associated with the final RICE NESHAP rule. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.
In July 2011, the EPA issued a proposed rule that would change the air emission New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification. Further, pursuant to various industry comments, administrative petitions for reconsideration and/or judicial appeals of portions of the NSPS final rule, the EPA has indicated it may provide certain responses, amendments and/or policy
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guidance to amend or clarify portions of the final rule in 2013. We anticipate that if the EPA issues additional responses, amendments and/or policy guidance on the final rule, it will reduce the anticipated capital, operations and maintenance costs resulting from the regulation. Generally, the NSPS final rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude-oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.
CERCLA - The federal Comprehensive Environmental Response, Compensation and Liability Act, also commonly known as Superfund (CERCLA), imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) that caused and/or contributed to the release of a hazardous substance into the environment. These persons include but are not limited to the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. Neither we nor ONEOK Partners expect our respective responsibilities under CERCLA, for this facility and any other, will have a material impact on our respective results of operations, financial position or cash flows.
Chemical Site Security - The United States Department of Homeland Security released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored. We completed the Homeland Security assessments, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, four of our facilities have been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and possible security enhancements cost will have a material impact on our results of operations, financial position or cash flows.
Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.
Environmental Footprint - Our environmental and climate change strategy focuses on taking steps to minimize the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate greenhouse gas emissions inventory according to current rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emission control and the capture of carbon dioxide to keep it from reaching the atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities.
We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.
EMPLOYEES
We employed 4,859 people at January 31, 2013, including 705 people at Kansas Gas Service who are subject to collective bargaining agreements. The following table sets forth our contracts with collective bargaining units at January 31, 2013:
Union | Employees | Contract Expires | ||
The United Steelworkers | 406 | October 28, 2016 | ||
International Brotherhood of Electrical Workers (IBEW) | 299 | June 30, 2014 | ||
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EXECUTIVE OFFICERS
All executive officers are elected annually by our Board of Directors and each serves until such person resigns, is removed or is otherwise disqualified to serve or until such officer’s successor is duly elected. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.
Name and Position | Age | Business Experience in Past Five Years | |||||
John W. Gibson | 60 | 2012 to present | Chairman and Chief Executive Officer, ONEOK and ONEOK Partners | ||||
Chairman and Chief Executive Officer | 2011 | Chairman, President and Chief Executive Officer, ONEOK | |||||
2011 | Vice Chairman of the Board of Directors, ONEOK | ||||||
2010 to 2011 | President and Chief Executive Officer, ONEOK | ||||||
2010 to 2011 | Chairman, President and Chief Executive Officer, ONEOK Partners | ||||||
2007 to 2009 | Chief Executive Officer, ONEOK | ||||||
2007 to 2009 | Chairman and Chief Executive Officer, ONEOK Partners | ||||||
2006 to present | Member of the Board of Directors, ONEOK and ONEOK Partners | ||||||
Terry K. Spencer | 53 | 2012 to present | President, ONEOK and ONEOK Partners | ||||
President | 2010 to present | Member of the Board of Directors, ONEOK Partners | |||||
2009 to 2011 | Chief Operating Officer, ONEOK Partners | ||||||
2007 to 2009 | Executive Vice President, Natural Gas Liquids, ONEOK Partners | ||||||
Pierce H. Norton II | 53 | 2013 to present | Executive Vice President, Commercial, ONEOK and ONEOK Partners | ||||
Executive Vice President, Commercial | 2012 | Executive Vice President and Chief Operating Officer, ONEOK and ONEOK Partners | |||||
2011 | Chief Operating Officer, ONEOK | ||||||
2009 to 2011 | President, ONEOK Distribution Companies, ONEOK | ||||||
2007 to 2009 | Executive Vice President, Natural Gas, ONEOK Partners | ||||||
Robert F. Martinovich | 55 | 2013 to present | Executive Vice President, Operations, ONEOK and ONEOK Partners | ||||
Executive Vice President, Operations | 2012 | Executive Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners | |||||
2011 to 2012 | Member of the Board of Directors, ONEOK Partners | ||||||
2011 | Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners | ||||||
2009 to 2011 | Chief Operating Officer, ONEOK | ||||||
2007 to 2009 | President, Gathering and Processing, ONEOK Partners | ||||||
Stephen W. Lake | 49 | 2012 to present | Senior Vice President, General Counsel and Assistant Secretary, ONEOK and ONEOK Partners | ||||
Senior Vice President, General Counsel and Assistant Secretary | 2011 | Senior Vice President, Associate General Counsel and Assistant Secretary, ONEOK and ONEOK Partners | |||||
2008 to 2011 | Executive Vice President and General Counsel, McJunkin Red Man Corporation | ||||||
1998 to 2008 | Partner, Gable & Gotwals, A Professional Corporation | ||||||
Derek S. Reiners | 41 | 2013 to present | Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners | ||||
Senior Vice President, Chief Financial Officer and Treasurer | 2009 to 2012 | Senior Vice President and Chief Accounting Officer, ONEOK and ONEOK Partners | |||||
2004 to 2009 | Partner, Grant Thornton LLP | ||||||
Sheppard F. Miers III | 44 | 2013 to present | Vice President and Chief Accounting Officer, ONEOK and ONEOK Partners | ||||
Vice President and Chief Accounting Officer | 2009 to 2012 | Vice President and Controller, ONEOK Partners | |||||
2005 to 2009 | Vice President, ONEOK | ||||||
No family relationships exist between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.
INFORMATION AVAILABLE ON OUR WEBSITE
We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.
We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.
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ITEM 1A. RISK FACTORS
Our investors should consider the following risks that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Annual Report, including “Forward-Looking Statements,” which are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
RISK FACTORS INHERENT IN OUR BUSINESS
Market volatility and capital availability could affect adversely our business.
The capital and global credit markets have experienced volatility and disruption in the past. In many cases during these periods, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for certain companies. Our ability to grow could be constrained if we do not have regular access to the capital and global credit markets. Similar or more severe levels of global market disruption and volatility may have an adverse affect on us resulting from, but not limited to, disruption of our access to capital and credit markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing cost and increasingly restrictive covenants.
Our operating results may be affected materially and adversely by unfavorable economic and market conditions.
Economic conditions worldwide have from time to time contributed to slowdowns in the oil and natural gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices may have an impact on many of our customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. If global economic and market conditions (including volatility in commodity markets), or economic conditions in the United States or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition, results of operations and liquidity.
Our cash flow depends heavily on the earnings and distributions of ONEOK Partners.
Our partnership interest in ONEOK Partners is one of our largest cash-generating assets. Therefore, our cash flow is heavily dependent upon the ability of ONEOK Partners to make distributions to its partners. A significant decline in ONEOK Partners’ earnings and/or cash distributions could have a corresponding negative impact on us. For information on the risk factors inherent in the business of ONEOK Partners, see the section below entitled “Additional Risk Factors Related to ONEOK Partners’ Business” and Item 1A, Risk Factors in the ONEOK Partners’ Annual Report.
Some of our nonregulated businesses have a higher level of risk than our regulated businesses.
Some of our nonregulated operations, which include ONEOK Partners’ natural gas gathering and processing business, most of its natural gas liquids business and our energy services business, have a higher level of risk than our regulated operations, which include the LDCs in our natural gas distribution business, ONEOK Partners’ natural gas pipelines business and a portion of its natural gas liquids business. We and ONEOK Partners expect to continue investing in natural gas and natural gas liquids projects and other related projects, some or all of which may involve nonregulated businesses or assets. These projects could involve risks associated with operational factors, such as competition and dependence on certain suppliers and customers, and financial, economic and political factors, such as rapid and significant changes in commodity prices, the cost and availability of capital and counterparty risk, including the inability of a counterparty, customer or supplier to fulfill a contractual obligation.
Our LDCs have recorded certain assets that may not be recoverable from our customers.
Accounting principles that govern our LDCs permit certain assets that result from the regulatory process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as rate orders from regulators, previous rate orders for substantially similar costs, written approval from the regulators and analysis of recoverability from internal and external legal counsel to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.
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Terrorist attacks aimed at our facilities could affect adversely our business.
Since the terrorist attacks on September 11, 2001, the United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments may subject our operations to increased risks. Any future terrorist attack that targets our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
Our businesses are subject to market and credit risks.
We are exposed to market and credit risks in all of our operations. To minimize the risk of commodity price fluctuations, we periodically enter into derivative transactions to hedge anticipated purchases and sales of natural gas, NGLs, crude oil, fuel requirements and firm transportation commitments. Interest-rate swaps are also used to manage interest-rate risk. Currency forward contracts are used to mitigate unexpected changes that may occur in anticipated revenue streams of our Canadian natural gas sales and purchases driven by currency rate fluctuations. However, financial derivative instrument contracts do not eliminate the risks. Specifically, such risks include commodity price changes, market supply shortages, interest-rate changes and counterparty default. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts, or increased interest expense.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by customers and counterparties of our Energy Services segment. The customers of our Energy Services segment are predominantly LDCs, industrial customers, natural gas producers and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their creditworthiness or ability to pay for our services. If we fail to assess adequately the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could adversely impact results of operations for our Energy Services segment. In addition, if any of our Energy Services segment’s customers or counterparties filed for bankruptcy protection, we may not be able to recover amounts owed, which could impact materially and adversely the results of operations for our Energy Services segment.
Increased competition could have a significant adverse financial impact on us.
The natural gas and natural gas liquids industries are expected to remain highly competitive. The demand for natural gas and NGLs is primarily a function of commodity prices, including prices for alternative energy sources, customer usage rates, weather, economic conditions and service costs. Our ability to compete also depends on a number of other factors, including competition from other companies for our existing customers, the efficiency, quality and reliability of the services we provide, and competition for throughput at ONEOK Partners’ gathering systems, pipelines, processing plants, fractionators and storage facilities.
We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows. There are no assurances that our business will be positioned to effectively compete in the future.
We may not be able to make additional strategic acquisitions or investments.
Our ability to make strategic acquisitions and investments will depend on:
• | the extent to which acquisitions and investment opportunities become available; |
• | our success in bidding for the opportunities that do become available; |
• | regulatory approval, if required, of the acquisitions or investments on favorable terms; and |
• | our access to capital, including our ability to use our equity in acquisitions or investments, and the terms upon which we obtain capital. |
If we are unable to make strategic investments and acquisitions, we may be unable to grow.
Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per-share basis.
Any acquisition involves potential risks that may include, among other things:
• | inaccurate assumptions about volumes, revenues and costs, including potential synergies; |
• | an inability to integrate successfully the businesses we acquire; |
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• | decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition; |
• | a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition; |
• | the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance policies may exclude from coverage; |
• | an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets; |
• | limitations on rights to indemnity from the seller; |
• | inaccurate assumptions about the overall costs of equity or debt; |
• | the diversion of management’s and employees’ attention from other business concerns; |
• | unforeseen difficulties operating in new product areas or new geographic areas; |
• | increased regulatory burdens; |
• | customer or key employee losses at an acquired business; and |
• | increased regulatory requirements. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.
We may engage in acquisitions, divestitures and other strategic transactions, the success of which may impact our results of operations.
We may engage in acquisitions, divestitures and other strategic transactions. If we are unable to integrate successfully businesses that we acquire with our existing business, our results of operations may be affected materially and adversely. Similarly, we may from time to time divest portions of our business, which may also affect materially and adversely our results of operations.
Any reduction in our credit ratings could affect materially and adversely our business, financial condition, liquidity and results of operations.
Our long-term senior unsecured debt has been assigned an investment-grade rating by S&P of “BBB” (Stable) and Moody’s of “Baa2” (Stable); however, we cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Specifically, if S&P or Moody’s were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which would affect adversely our financial results, and our potential pool of investors and funding sources could decrease. Further, if our short-term ratings were to fall below A-2 or Prime-2, the current ratings assigned by S&P and Moody’s, respectively, it could limit significantly our access to the commercial paper market. Any such downgrade of our long- or short-term ratings could increase significantly our cost of capital and reduce the availability of capital and, thus, have a material adverse effect on our business, financial condition, liquidity and results of operations. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.
A downgrade in our credit ratings below investment grade would affect negatively the operations of our Energy Services segment. If our credit ratings fall below investment grade, ratings triggers and/or adequate assurance clauses in many of our financial and wholesale physical contracts would be in effect. A ratings trigger or adequate assurance clause gives a counterparty the right to suspend or terminate the agreement unless margin thresholds are met. Margin requirements related to the trading activities of our Energy Services segment may also increase as a result of market volatility without regard to our credit rating. The additional increase in capital required to support our Energy Services segment would impact materially and adversely our ability to compete, as well as our ability to manage actively the risk associated with existing storage and transportation contracts.
Our established risk-management policies and procedures may not be effective, and employees may violate our risk-management policies.
We have developed and implemented a set of policies and procedures that involve both our senior management and the Audit Committee of our Board of Directors to assist us in managing risks associated with, among other things, the marketing, trading and risk-management activities associated with our business segments. Our risk policies and procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is managed throughout the organization. As conditions change and become more complex, current risk measures may fail to assess adequately the relevant risk due to changes in the market and the presence of risks previously unknown to us. Additionally, if employees fail to adhere
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to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended. Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have an adverse affect on our earnings, financial position or cash flows.
Our indebtedness could impair our financial condition and our ability to fulfill our obligations.
As of December 31, 2012, we had total indebtedness for borrowed money of approximately $1.7 billion, which excludes the debt of ONEOK Partners. Our indebtedness could have significant consequences. For example, it could:
• | make it more difficult for us to satisfy our obligations with respect to our senior notes and our other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or our senior notes; |
• | impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes; |
• | diminish our ability to withstand a downturn in our business or the economy; |
• | require us to dedicate a substantial portion of our cash flow from operations to debt-service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, or general corporate purposes; |
• | limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and |
• | place us at a competitive disadvantage compared with our competitors that have proportionately less debt. |
We are not prohibited under the indentures governing our senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations summarized in the next paragraph. If we incur significant additional indebtedness, it could worsen the negative consequences mentioned above and could affect adversely our ability to repay our other indebtedness.
Our revolving debt agreements with banks contain provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, certain of these agreements contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Certain agreements also require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in the “Liquidity and Capital Resources” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants.
If we are unable to meet our debt-service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on regulatory action.
We are subject to comprehensive regulation by several federal, state and municipal utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility regulatory authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including customer service and the rates that we can charge customers. Federal, state and local agencies also have jurisdiction over many of our other activities, including regulation by the FERC of our storage and interstate pipeline assets. The profitability of our regulated operations is dependent on our ability to pass through costs related to providing energy and other commodities to our customers by filing periodic rate cases. The regulatory environment applicable to our regulated businesses could impair our ability to recover costs historically absorbed by our customers.
We are unable to predict the impact that the future regulatory activities of these agencies will have on our operating results. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and results of operations. Further, the results of our LDCs’ operations could be impacted negatively if the cost-recovery mechanisms authorized by our rate cases do not function as anticipated.
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The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
In July 2010, the Dodd-Frank Act was enacted, which provides for new statutory and regulatory requirements for certain swap transactions. Certain financial transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions. However, the Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and to the parties to those transactions. Additionally, the Dodd-Frank Act calls for various regulatory agencies, including the SEC and the CFTC, to establish regulations for implementation of many of the provisions of the act.
The SEC and CFTC have proposed regulations for implementation of many provisions of the Dodd-Frank Act. The CFTC has issued final regulations for many provisions of the Dodd-Frank Act that have varying effective dates for compliance, but others remain outstanding. Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations. These requirements could affect adversely the liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties will likely be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
The volatility of natural gas prices may impact negatively LDC customers’ perception of natural gas.
Natural gas costs are passed through to the customers of our LDCs based on the actual cost of the natural gas purchased by the particular LDC. Substantial fluctuations in natural gas prices can occur from year to year. Sustained periods of high natural gas prices or of pronounced natural gas price volatility may impact negatively our LDC customers’ perception of natural gas, which could lead to customers selecting other energy alternatives, such as electricity, and to difficulties in the rate-making process. Additionally, high natural gas prices may cause customers to conserve more and may also impact adversely our accounts receivable collections, resulting in higher bad-debt expense.
Our business is subject to regulatory oversight and potential penalties.
The natural gas industry historically has been subject to heavy state and federal regulation that extends to many aspects of our businesses and operations, including:
• | rates, operating terms and conditions of service; |
• | the types of services we may offer our customers; |
• | construction of new facilities; |
• | the integrity, safety and security of facilities and operations; |
• | acquisition, extension or abandonment of services or facilities; |
• | reporting and information posting requirements; |
• | maintenance of accounts and records; and |
• | relationships with affiliate companies involved in all aspects of the natural gas and energy businesses. |
Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of operations.
We cannot guarantee that state or federal regulators will authorize any projects or acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions.
Failure to comply with all applicable state or federal statutes, rules and regulations and orders, could bring substantial penalties and fines. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation.
Finally, we cannot give any assurance regarding future state or federal regulations under which we will operate or the effect such regulations could have on our business, financial condition and results of operations.
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Demand for services of our Natural Gas Distribution and Energy Services segments and for certain of ONEOK Partners’ products is highly weather sensitive and seasonal.
The demand for natural gas in our Natural Gas Distribution, Energy Services and ONEOK Partners segments and for certain of ONEOK Partners’ products, such as propane, is weather sensitive and seasonal, with a significant portion of revenues derived from sales for heating during the winter months. Weather conditions influence directly the volume of, among other things, natural gas and propane delivered to customers. Deviations in weather from normal levels and the seasonal nature of certain of our segments’ business can create large variations in earnings and short-term cash requirements.
Compliance with environmental regulations that we are subject to may be difficult and costly.
We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid and hazardous wastes and hazardous material and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If a leak or spill of hazardous substance occurs from our lines or facilities in the process of transporting natural gas or NGLs or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could affect materially our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. In addition, the EPA issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, with a compliance date in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations. For further discussion on this topic, see Note Q of the Notes to Consolidated Financial Statements in this Annual Report.
We are subject to risks that could limit our access to capital, thereby increasing our costs and affecting adversely our results of operations.
We have grown rapidly in the past as a result of acquisitions. Future acquisitions may require additional capital. If we are unable to access capital at competitive rates, our strategy of enhancing the earnings potential of our existing assets, including through acquisitions of complementary assets or businesses, will be affected adversely. A number of factors could affect adversely our ability to access capital, including: (i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other hydrocarbons; (iv) the overall health of the energy and related industries; (v) our ability to maintain our investment-grade credit ratings; and (vi) our capital structure. Much of our business is capital intensive, and achievement of our long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive. If our ability to access capital becomes constrained significantly, our interest costs will likely increase and our financial condition and future results of operations could be harmed significantly.
Energy efficiency and technological advances may affect the demand for natural gas and affect adversely our operating results.
The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may decrease the demand for natural gas by residential customers. More strict conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could affect adversely our operations.
The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase.
We have a defined benefit pension plan for certain employees and postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their
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beneficiaries and changes in health care costs. For further discussion of our defined benefit pension plan, see Note M of the Notes to Consolidated Financial Statements in this Annual Report.
Any sustained declines in equity markets and reductions in bond yields may have a material adverse effect on the value of our pension and postretirement benefit plan assets. In these circumstances, additional cash contributions to our pension plans may be required.
Our business could be affected adversely by strikes or work stoppages by our unionized employees.
As of January 31, 2013, 705 of our 4,859 employees were represented by collective bargaining units under collective bargaining agreements. We are involved periodically in discussions with collective bargaining units representing some of our employees to negotiate or renegotiate labor agreements. We cannot predict the results of these negotiations, including whether any failure to reach new agreements will have a negative effect on our business, financial condition and results of operations or whether we will be able to reach any agreement with the collective bargaining units. Any failure to reach agreement on new labor contracts might result in a work stoppage. Any future work stoppage could, depending on the operations and the length of the work stoppage, have a material adverse effect on our business, financial condition and results of certain operations.
We may face significant costs to comply with the regulation of greenhouse gas emissions.
Greenhouse gas emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. Various federal and state legislative proposals have been introduced to regulate the emission of greenhouse gases, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of greenhouse gases.
We believe it is possible that future governmental legislation and/or regulation may require us either to limit greenhouse gas emissions from our operations or to purchase allowances for such emissions that are actually attributable to our distribution customers or attributable to NGL customers of ONEOK Partners. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations, or when they will become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of greenhouse gases that can be emitted (so called “caps”) together with systems of emissions allowances. This system could require us to reduce emissions, even though the technology is not currently available for efficient reduction, or to purchase allowances for such emissions. Emissions also could be taxed independently of limits.
In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of greenhouse gas emissions sooner and/or independent of federal regulation. These regulations could be more stringent than any federal regulation or legislation that is adopted.
Future legislation and/or regulation designed to reduce greenhouse gas emissions could make some of our activities uneconomic to maintain or operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with greenhouse gas regulatory requirements. Our future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to our customers.
We continue to monitor legislative and regulatory developments in this area. Although the regulation of greenhouse gas emissions may have a material impact on our operations and rates, we are unable to quantify the potential costs of the impacts at this time.
We may not be able to pass on the higher costs to our customers or recover all costs related to complying with greenhouse gas emission regulatory requirements, which could cause material adverse effects on our business, financial condition, results of operations and cash flows.
We do not hedge fully against commodity price changes, time differentials or locational differentials. This could result in decreased revenues and increased costs, thereby resulting in lower margins and adversely affecting our results of operations.
Certain of our nonregulated and regulated businesses are exposed to market risk and the impact of market price fluctuations of natural gas, NGLs and crude oil. Market risk refers to the risk of loss of cash flows and future earnings arising from adverse
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changes in commodity prices. Our Energy Services segment’s primary exposures arise from seasonal and location price differentials and our ability to execute hedges. Our ONEOK Partners segment’s primary exposures arise from:
• | the value of the NGLs and natural gas it receives in exchange for the natural gas gathering and processing services it provides; |
• | the differentials between NGL and natural gas prices associated with its keep-whole contracts and the differentials between the individual NGL products with respect to ONEOK Partners’ natural gas liquids transportation and fractionation agreements; |
• | the differentials between the individual NGL products; |
• | the NGL price differentials at different locations; |
• | the seasonal price differentials of natural gas and NGLs related to storage operations; |
• | the fuel costs and the value of the retained fuel in-kind in ONEOK Partners’ natural gas pipelines and storage operations; and |
• | the differential between ethane and natural gas prices. |
Our ONEOK Partners and Energy Services segments also are exposed to the risk of changing prices or the cost of transportation resulting from purchasing natural gas or NGLs at one location and selling it at another (referred to as basis risk). To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use physical forward transactions and commodity financial derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchases and sales of natural gas, NGLs and crude oil. We adhere to policies and procedures that monitor our exposure to market risk from open positions. However, we do not hedge fully against commodity price changes, and therefore, we retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and/or increased costs.
Our Natural Gas Distribution segment uses storage to minimize the volatility of natural gas costs for our customers by storing natural gas in periods of low demand for consumption in peak-demand periods. In addition, various natural gas supply contracts allow us the option to convert index-based purchases to fixed prices. Also, we use derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect customers from upward volatility in the market price of natural gas.
Federal, state and local jurisdictions may challenge our tax return positions.
The positions taken in our federal and state tax return filings require significant judgments, use of estimates and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite management’s belief that our tax return positions are fully supportable, certain positions may be successfully challenged by federal, state and local jurisdictions.
Although we control ONEOK Partners, we may have conflicts of interest with ONEOK Partners that could subject us to claims that we have breached our fiduciary duty to ONEOK Partners and its unitholders.
We are the sole general partner and own 43.4 percent of ONEOK Partners. Conflicts of interest may arise between us and ONEOK Partners and its unitholders. In resolving these conflicts, we may favor our own interests and the interests of our affiliates over the interests of ONEOK Partners and its unitholders as long as the resolution does not conflict with the ONEOK Partners’ partnership agreement or our fiduciary duties to ONEOK Partners and its unitholders.
We are subject to physical and financial risks associated with climate change.
There is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornados and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a
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financial risk, this could affect negatively our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change.
Both our and ONEOK Partners’ operations are subject to operational hazards and unforeseen interruptions that could affect materially and adversely our and ONEOK Partners’ business and for which neither we nor ONEOK Partners may be insured adequately.
Our and ONEOK Partners’ operations are subject to all of the risks and hazards typically associated with the operation of natural gas and natural gas liquids gathering, transportation and distribution pipelines, storage facilities and processing and fractionation plants. Operating risks include but are not limited to leaks, pipeline ruptures, the breakdown or failure of equipment or processes, and the performance of pipeline facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision of equipment with our or ONEOK Partners’ pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near our or ONEOK Partners’ facilities) and catastrophic events such as tornados, hurricanes, earthquakes, floods or other similar events beyond our or ONEOK Partners’ control. It is also possible that our or ONEOK Partners’ facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred and interruptions to the operations of our or ONEOK Partners’ pipelines or other facilities caused by such an event could reduce revenues generated by us or ONEOK Partners and increase expenses, thereby impairing our or ONEOK Partners’ ability to meet our respective obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and neither we nor ONEOK Partners are fully insured against all risks inherent in our respective businesses.
As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, neither we nor ONEOK Partners may be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. If either we or ONEOK Partners were to incur a significant liability for which either we or ONEOK Partners was not insured fully, it could have a material adverse effect on our or ONEOK Partners’ financial position and results of operations. Further, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Our use of financial instruments and physical forward transactions to hedge market risk may result in reduced income.
We utilize financial instruments and physical forward transactions to mitigate our exposure to commodity price and interest-rate fluctuations. Hedging arrangements that are used to reduce our exposure to commodity price fluctuations limit the benefit we would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the stated price in the hedge instrument for these commodities. Hedging instruments that are used to reduce our exposure to interest-rate fluctuations could expose us to risk of financial loss where we have contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate. In addition, these hedging arrangements may limit the benefit we would otherwise receive if we had contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate.
An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.
Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments ONEOK Partners accounts for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if natural gas production continues to decline in the Powder River Basin, ONEOK Partners could be unable to recover the carrying value of its assets and equity investments in this area. If ONEOK Partners determines that an impairment is indicated, it would be required to take an immediate noncash charge to earnings with a correlative effect on our equity and balance sheet leverage as measured by consolidated debt to total capitalization.
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A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.
Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be affected adversely. Our financial results could also be affected adversely if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our businesses. We use computer programs to help run our financial and operations organizations, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse on our businesses. In addition, cyber attacks on our customer and employee data may result in a financial loss and may impact negatively our reputation.
Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt one or more of our businesses, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results.
Changes in interest rates could affect adversely our business.
We use both fixed- and variable-rate debt, and we are exposed to market risk due to the floating interest rates on our short-term borrowings. From time to time we use interest-rate derivatives to hedge interest obligations on specific debt issuances, including anticipated debt issuances. These hedges may be ineffective, and our results of operations, cash flows and financial position could be affected adversely by significant fluctuations or increases or decreases in interest rates from current levels.
We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which could disrupt our operations.
We do not own all of the land on which certain of our pipelines and facilities are located and are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could affect operations and cash flows available for distribution.
Our operations require skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs. This shortage of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the difficulty of attracting new workers to the midstream energy industry. This shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could affect adversely our operations and cash flows available for distribution to unitholders.
Pipeline-integrity programs and repairs may impose significant costs and liabilities.
Pursuant to a DOT rule, pipeline operators are required to develop integrity-management programs for intrastate and interstate natural gas and natural gas liquids pipelines that could affect high-consequence areas in the event of a release of product. As defined by applicable regulations, high-consequence areas include areas near the route of a pipeline with high-population densities, facilities occupied by persons of limited mobility or indoor or outdoor areas where at least 20 people gather periodically. The rule requires operators to identify pipeline segments that could impact a high-consequence area; improve data collection, integration and characterization of threats applicable to each segment; implement preventive and mitigating actions; perform ongoing assessments of pipeline integrity; and repair and remediate as necessary. These testing programs could cause us and ONEOK Partners to incur significant capital and operating expenditures to make repairs or remediate, as well as initiate preventive or mitigating actions that are determined to be necessary.
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We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could affect adversely financial results.
The workplaces associated with our facilities are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. The failure to comply with OSHA requirements or general industry standards, including keeping adequate records or occupational exposure to regulated substances could expose us to civil or criminal liability, enforcement actions, and regulatory fines and penalties and could have a material adverse effect on our business, financial position, results of operations and cash flow.
Measurement adjustments on our pipeline system can be impacted materially by changes in estimation, type of commodity and other factors.
Natural gas and natural gas liquids measurement adjustments occur as part of the normal operating conditions associated with our assets. The quantification and resolution of measurement adjustments are complicated by several factors including: (1) the significant number (i.e., thousands) of meters that we use throughout our natural gas and natural gas liquids systems; (2) varying qualities of natural gas in the streams gathered and processed and the mixed nature of NGLs gathered and fractionated through ONEOK Partners’ systems; and (3) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that can occur on our systems, which could affect negatively our earnings and cash flows.
ADDITIONAL RISK FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS
The volatility of natural gas, crude oil and NGL prices could affect adversely ONEOK Partners’ cash flow.
A significant portion of ONEOK Partners’ revenues are derived from the sale of commodities that are received as payment for natural gas gathering and processing services, for the transportation and storage of natural gas, and for the sale of NGLs and NGL products in ONEOK Partners’ natural gas liquids business. Commodity prices have been volatile and are likely to continue to be so in the future. The prices ONEOK Partners receives for its commodities are subject to wide fluctuations in response to a variety of factors beyond ONEOK Partners’ control, including, but not limited to, the following:
• | overall domestic and global economic conditions; |
• | relatively minor changes in the supply of, and demand for, domestic and foreign energy; |
• | market uncertainty; |
• | the availability and cost of third-party transportation, natural gas processing and natural gas liquids fractionation capacity; |
• | the level of consumer product demand; |
• | ethane rejection; |
• | geopolitical conditions impacting supply and demand for natural gas, NGLs and crude oil; |
• | weather conditions; |
• | domestic and foreign governmental regulations and taxes; |
• | the price and availability of alternative fuels; |
• | speculation in the commodity futures markets; |
• | overall domestic and global economic conditions; |
• | the price of natural gas, crude oil, NGL and liquefied natural gas imports and exports; |
• | the effect of worldwide energy conservation measures; and |
• | the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials. |
These external factors and the volatile nature of the energy markets make it difficult to estimate reliably future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services. As commodity prices decline, ONEOK Partners is paid less for its commodities, thereby reducing its cash flow. NGL volumes could decline if it becomes uneconomical for natural gas processors to recover the ethane component of the natural gas stream as a separate product. In addition, crude-oil and natural gas production could also decline due to lower prices.
ONEOK Partners’ inability to develop and execute growth projects and acquire new assets could result in reduced cash distributions to its unitholders and to ONEOK.
ONEOK Partners’ primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to unitholders and to increase quarterly cash distributions over time. ONEOK Partners’ ability to maintain and grow its
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distributions to unitholders, including ONEOK, depends on the growth of its existing businesses and strategic acquisitions. Accordingly, if ONEOK Partners is unable to implement business development opportunities and finance such activities on economically acceptable terms, its future growth will be limited, which could impact adversely its and our results of operations and cash flows.
Growing ONEOK Partners’ business by constructing new pipelines and plants or making modifications to its existing facilities subjects ONEOK Partners to construction and supply risks should adequate natural gas or NGL supply be unavailable upon completion of the facilities.
One of the ways ONEOK Partners intends to grow its business is through the construction of new pipelines and new gathering, processing, storage and fractionation facilities and through modifications to ONEOK Partners’ existing pipelines and existing gathering, processing, storage and fractionation facilities. The construction and modification of pipelines and gathering, processing, storage and fractionation facilities may require significant capital expenditures, which may exceed ONEOK Partners’ estimates, and involves numerous regulatory, environmental, political, legal and weather-related uncertainties. Construction projects in ONEOK Partners’ industry may increase demand for labor, materials and rights of way, which, may, in turn, impact ONEOK Partners’ costs and schedule. If ONEOK Partners undertakes these projects, it may not be able to complete them on schedule or at the budgeted cost. Additionally, ONEOK Partners’ revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if ONEOK Partners builds a new pipeline, the construction will occur over an extended period of time, and ONEOK Partners will not receive any material increases in revenues until after completion of the project. ONEOK Partners may have only limited natural gas or NGL supply committed to these facilities prior to their construction. Additionally, ONEOK Partners may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. ONEOK Partners may also rely on estimates of proved reserves in its decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve ONEOK Partners’ expected investment return, which could affect materially and adversely ONEOK Partners’ results of operations, financial condition and cash flows.
If the level of drilling and production in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions declines substantially near its assets, ONEOK Partners’ volumes and revenue could decline.
ONEOK Partners’ ability to maintain or expand its businesses depends largely on the level of drilling and production by third parties in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions. Drilling and production are impacted by factors beyond ONEOK Partners’ control, including:
• | demand and prices for natural gas, NGLs and crude oil; |
• | producers’ finding and developing costs of reserves; |
• | producers’ desire and ability to obtain necessary permits in a timely and economic manner; |
• | natural gas field characteristics and production performance; |
• | surface access and infrastructure issues; and |
• | capacity constraints on natural gas, crude oil and natural gas liquids infrastructure from the producing areas and ONEOK Partners’ facilities. |
If production from the Western Canada Sedimentary Basin remains flat or declines, and demand for natural gas from the Western Canada Sedimentary Basin is greater in market areas other than the Midwestern United States, demand for ONEOK Partners’ interstate gas transportation services could decrease significantly.
ONEOK Partners depends on natural gas supply from the Western Canada Sedimentary Basin for some of ONEOK Partners’ interstate pipelines, primarily Viking Gas Transmission and ONEOK Partners’ investment in Northern Border Pipeline, that transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern United States market area. If demand for natural gas increases in Canada or other markets not served by ONEOK Partners’ interstate pipelines and/or production remains flat or declines, demand for transportation service on ONEOK Partners’ interstate natural gas pipelines could decrease significantly, which could impact adversely ONEOK Partners’ results of operations and cash flows.
ONEOK Partners’ regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.
Under the Natural Gas Act, which is applicable to interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to crude oil and natural gas liquids pipelines, ONEOK Partners’ interstate transportation rates, which are regulated by the FERC, must be just and reasonable and not unduly discriminatory.
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Shippers may protest ONEOK Partners’ pipeline tariff filings, and the FERC and/or state regulatory agencies may investigate tariff rates. Further, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to be in excess of a just and reasonable level. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. The FERC and/or state regulatory agencies also may investigate tariff rates absent shipper complaint. Any finding that approved rates exceed a just and reasonable level on the natural gas pipelines would take effect prospectively. In a complaint proceeding challenging natural gas liquids pipeline rates, if the FERC determines existing rates exceed a just and reasonable level, it could require the payment of reparations to complaining shippers for up to two years prior to the complaint. Any such action by the FERC or a comparable action by a state regulatory agency could affect adversely ONEOK Partners’ pipeline businesses’ ability to charge rates that would cover future increases in costs, or even to continue to collect rates that cover current costs and provide for a reasonable return. We can provide no assurance that ONEOK Partners’ pipeline systems will be able to recover all of their costs through existing or future rates.
ONEOK Partners’ regulated pipeline companies have recorded certain assets that may not be recoverable from its customers.
Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on ONEOK Partners’ balance sheet that could not be recorded under GAAP for nonregulated entities. ONEOK Partners considers factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If ONEOK Partners determines future recovery is no longer probable, ONEOK Partners would be required to write off the regulatory assets at that time.
ONEOK Partners’ operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose it to significant costs and liabilities.
The risk of incurring substantial environmental costs and liabilities is inherent in ONEOK Partners’ business. ONEOK Partners’ operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment. Examples of these laws include:
• | the Clean Air Act and analogous state laws that impose obligations related to air emissions; |
• | the Clean Water Act and analogous state laws that regulate discharge of waste water from ONEOK Partners’ facilities to state and federal waters; |
• | the federal CERCLA and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by ONEOK Partners or locations to which ONEOK Partners has sent waste for disposal; |
• | the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from ONEOK Partners’ facilities; and |
• | an EPA-issued rule on air-quality standards, known as RICE NESHAP. |
Various federal and state governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.
There is an inherent risk of incurring environmental costs and liabilities in ONEOK Partners’ business due to its handling of the products it gathers, transports, processes and stores, air emissions related to its operations, past industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which ONEOK Partners’ pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from ONEOK Partners’ operations. Some sites ONEOK Partners operates are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ONEOK Partners’ sites. In addition, increasingly strict laws, regulations and enforcement policies could increase significantly ONEOK Partners’ compliance costs and the cost of any remediation that may become necessary, some of which may be material. Additional information is included under Item 1, Business under “Environmental and Safety Matters” and in Note Q of the Notes to Consolidated Financial Statements in this Annual Report.
ONEOK Partners’ insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against ONEOK Partners. ONEOK Partners’ business may be affected materially and adversely by increased costs due to stricter pollution-control requirements or liabilities resulting from noncompliance with
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required operating or other regulatory permits. New environmental regulations might also materially and adversely affect ONEOK Partners’ products and activities, and federal and state agencies could impose additional safety requirements, all of which could affect materially ONEOK Partners’ profitability.
In the competition for customers, ONEOK Partners may have significant levels of uncontracted or discounted capacity on its natural gas and natural gas liquids pipelines, processing, fractionation and storage assets.
ONEOK Partners’ natural gas and natural gas liquids pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage facilities for natural gas and NGL supplies delivered to the markets it serves. As a result of competition, at any given time ONEOK Partners may have significant levels of uncontracted or discounted capacity on its pipelines, processing, fractionation and in its storage assets, which could have a material adverse impact on ONEOK Partners’ results of operations.
ONEOK Partners is exposed to the credit risk of its customers or counterparties, and its credit risk management may not be adequate to protect against such risk.
ONEOK Partners is subject to the risk of loss resulting from nonpayment and/or nonperformance by ONEOK Partners’ customers or counterparties. ONEOK Partners’ customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their creditworthiness or ability to pay ONEOK Partners for its services. ONEOK Partners assesses the creditworthiness of its customers or counterparties and obtains collateral as it deems appropriate. If ONEOK Partners fails to assess adequately the creditworthiness of existing or future customers or counterparties, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could adversely impact ONEOK Partners’ results of operations. In addition, if any of ONEOK Partners’ customers or counterparties files for bankruptcy protection, this could have a material negative impact on ONEOK Partners’ results of operations.
Any reduction in ONEOK Partners’ credit ratings could affect materially and adversely its business, financial condition, liquidity and results of operations.
ONEOK Partners’ senior unsecured long-term debt has been assigned an investment-grade rating by Moody’s of “Baa2” (Stable) and by S&P of “BBB” (Stable); however, we cannot provide assurance that any of its current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Specifically, if Moody’s or S&P were to downgrade ONEOK Partners’ long-term debt rating, particularly below investment grade, its borrowing costs would increase, which would affect adversely its financial results, and its potential pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or hold ONEOK Partners’ securities. Each rating should be evaluated independently of any other rating.
An event of default may require ONEOK Partners to offer to repurchase certain of its senior notes or may impair its ability to access capital.
The indentures governing ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in full. ONEOK Partners may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause ONEOK Partners to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases and repayment. ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.
ONEOK Partners’ indebtedness could impair its financial condition and ability to fulfill its obligations.
As of December 31, 2012, ONEOK Partners had total indebtedness of approximately $4.8 billion. Its indebtedness could have significant consequences. For example, it could:
• | make it more difficult to satisfy its obligations with respect to its senior notes and other indebtedness, which could in turn result in an event of default on such other indebtedness or its senior notes; |
• | impair its ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes; |
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• | diminish its ability to withstand a downturn in its business or the economy; |
• | require it to dedicate a substantial portion of its cash flow from operations to debt-service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, distributions to partners and general partnership purposes; |
• | limit its flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and |
• | place it at a competitive disadvantage compared with its competitors that have proportionately less debt. |
ONEOK Partners is not prohibited under the indentures governing its senior notes from incurring additional indebtedness, but its debt agreements do subject it to certain operational limitations summarized in the next paragraph. ONEOK Partners’ incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above and could affect adversely its ability to repay its senior notes and other indebtedness.
ONEOK Partners’ debt agreements contain provisions that restrict its ability to finance future operations or capital needs or to expand or pursue its business activities. For example, certain of these agreements contain provisions that, among other things, limit its ability to make loans or investments, make material changes to the nature of its business, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Certain agreements also require it to maintain certain financial ratios, which limit the amount of additional indebtedness it can incur. For example, the ONEOK Partners Credit Agreement contains a legal covenant requiring it to maintain a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1.
These restrictions could result in higher costs of borrowing and impair its ability to generate additional cash. Future financing agreements ONEOK Partners may enter into may contain similar or more restrictive covenants.
If ONEOK Partners is unable to meet its debt-service obligations, it could be forced to restructure or refinance its indebtedness, seek additional equity capital or sell assets. It may be unable to obtain financing, raise equity or sell assets on satisfactory terms, or at all.
Borrowings under the ONEOK Partners Credit Agreement and its senior notes are nonrecourse to ONEOK, and ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners.
ONEOK Partners has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of its limited partner units.
When ONEOK Partners issues additional units or engages in certain other transactions, ONEOK Partners determines the fair market value of its assets and allocates any unrealized gain or loss attributable to its assets to the capital accounts of its unitholders and its general partner. ONEOK Partners’ methodology may be viewed as understating the value of its assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under ONEOK Partners’ current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ONEOK Partners’ tangible assets and a lesser portion allocated to ONEOK Partners’ intangible assets. The IRS may challenge ONEOK Partners’ valuation methods or ONEOK Partners’ allocation of the Section 743(b) adjustment attributable to ONEOK Partners’ tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of ONEOK Partners’ unitholders.
A successful IRS challenge to these methods or allocations could affect adversely the amount of taxable income or loss being allocated to ONEOK Partners’ unitholders. It also could affect the amount of gain from ONEOK Partners unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to ONEOK Partners unitholders’ tax returns without the benefit of additional deductions.
ONEOK Partners’ treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units.
Because ONEOK Partners cannot match transferors and transferees of common units, ONEOK Partners is required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. ONEOK Partners does so by adopting certain depreciation conventions that do not conform to all aspects of existing United States Treasury regulations. A successful IRS challenge to these conventions could affect adversely the tax benefits to a
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unitholder of ownership of the common units and could have a negative impact on their value or result in audit adjustments to ONEOK Partners unitholders’ tax returns.
Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could impact adversely ONEOK Partners’ revenues by decreasing the volumes of unprocessed natural gas and NGLs transported on its or its joint ventures natural gas and natural gas liquids pipelines.
The natural gas industry is relying increasingly on natural gas supplies from unconventional sources, such as shale, tight sands and coal-bed methane gas. Natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate natural gas production. Recently, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing, and several states have adopted regulations that impose more stringent permitting, disclosure and well-completion requirements on hydraulic fracturing operations. Legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of unprocessed natural gas and, in turn, adversely affect ONEOK Partners’ revenues and results of operations by decreasing the volumes of unprocessed natural gas and NGLs gathered, treated, processed, fractionated and transported on ONEOK Partners’ or its joint ventures’ natural gas and natural gas liquids pipelines, several of which gather unprocessed natural gas and NGLs from areas where the use of hydraulic fracturing is prevalent.
Continued development of new supply sources could impact demand.
The discovery of unconventional natural gas production areas closer to certain market areas that ONEOK Partners serves may compete with natural gas originating in production areas connected to ONEOK Partners’ systems. For example, the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio may cause natural gas in supply areas connected to ONEOK Partners’ systems to be diverted to markets other than its traditional market areas and may affect capacity utilization adversely on ONEOK Partners’ pipeline systems and ONEOK Partners’ ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows. In addition, supply volumes from these nonconventional natural gas production areas may compete with and displace volumes from the Mid-Continent, Rocky Mountains and Canadian supply sources in certain of ONEOK Partners’ markets. The displacement of natural gas originating in supply areas connected to ONEOK Partners’ pipeline systems by these new supply sources that are closer to the end-use markets could result in lower transportation revenues, which could have a material adverse impact on ONEOK Partners’ business, financial condition, results of operations and cash flows.
A court may use fraudulent conveyance considerations to avoid or subordinate ONEOK Partners Intermediate Limited Partnership’s guarantee of certain of ONEOK Partners’ senior notes.
Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use fraudulent conveyance laws to subordinate or avoid the guarantee of certain of ONEOK Partners’ senior notes issued by ONEOK Partners Intermediate Limited Partnership. It is also possible that under certain circumstances, a court could hold that the direct obligations of the Intermediate Partnership could be superior to the obligations under that guarantee.
A court could avoid or subordinate the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes in favor of the Intermediate Partnership’s other debts or liabilities to the extent that the court determined either of the following were true at the time the Intermediate Partnership issued the guarantee:
• | the Intermediate Partnership incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the Intermediate Partnership contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or |
• | the Intermediate Partnership did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the Intermediate Partnership: |
– was insolvent or rendered insolvent by reason of the issuance of the guarantee;
– | was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or |
– intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.
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The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if:
• | the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation; |
• | the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or |
• | it could not pay its debts as they become due. |
Among other things, a legal challenge of the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes on fraudulent conveyance grounds may focus on the benefits, if any, realized by the Intermediate Partnership as a result of ONEOK Partners’ issuance of such senior notes. To the extent the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such senior notes would cease to have any claim in respect of the guarantee.
ONEOK Partners may be unable to cause its joint ventures to take or not to take certain actions unless some or all of its joint-venture participants agree.
ONEOK Partners participates in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100 percent) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint-venture participants with enough voting interests, ONEOK Partners may be unable to cause any of its joint ventures to take or not to take certain actions, even though those actions may be in the best interest of ONEOK Partners or the particular joint venture.
Moreover, any joint-venture owner generally may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners. Any such transaction could result in ONEOK Partners being required to partner with different or additional parties.
ONEOK Partners’ operating cash flow is derived partially from cash distributions it receives from its unconsolidated affiliates.
ONEOK Partners’ operating cash flow is derived partially from cash distributions it receives from its unconsolidated affiliates, as discussed in Note O of the Notes to Consolidated Financial Statements. The amount of cash that ONEOK Partners’ unconsolidated affiliates can distribute principally depends upon the amount of cash flow these affiliates generate from their respective operations, which may fluctuate from quarter to quarter. ONEOK Partners does not have any direct control over the cash distribution policies of its unconsolidated affiliates. This lack of control may contribute to ONEOK Partners’ not having sufficient available cash each quarter to continue paying distributions at its current levels.
Additionally, the amount of cash that ONEOK Partners has available for cash distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by noncash items such as depreciation, amortization and provisions for asset impairments. As a result, ONEOK Partners may be able to make cash distributions during periods when it records losses and may not be able to make cash distributions during periods when it records net income.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
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ITEM 2. PROPERTIES
DESCRIPTION OF PROPERTIES
ONEOK Partners
Property - Our ONEOK Partners segment owns the following assets:
• | approximately 10,900 miles and 6,200 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions, respectively; |
• | nine natural gas processing plants with approximately 645 MMcf/d of processing capacity in the Mid-Continent region, and six natural gas processing plants, with approximately 315 MMcf/d of processing capacity, in the Rocky Mountain region; |
• | approximately 24 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions; |
• | approximately 1,500 miles of FERC-regulated interstate natural gas pipelines with approximately 3.1 Bcf/d of peak transportation capacity; |
• | approximately 5,100 miles of state-regulated intrastate transmission pipelines with approximately 3.0 Bcf/d of peak transportation capacity; |
• | approximately 51.7 Bcf of total active working natural gas storage capacity; |
• | approximately 2,700 miles of natural gas liquids gathering pipelines with peak gathering capacity of approximately 772 MBbl/d; |
• | approximately 170 miles of natural gas liquids distribution pipelines with approximately 66 MBbl/d of peak transportation capacity; |
• | two natural gas liquids fractionators with approximately 260 MBbl/d of combined operating capacity, which are located in Oklahoma and Kansas; |
• | a natural gas liquids fractionator with operating capacity of 210 MBbl/d located at the Bushton facility in Kansas; |
• | 80-percent ownership interest in one natural gas liquids fractionator in Texas with ONEOK Partners’ proportional share of operating capacity of approximately 128 MBbl/d; |
• | interest in one natural gas liquids fractionator in Kansas with ONEOK Partners’ proportional share of operating capacity of approximately 11 MBbl/d; |
• | one isomerization unit in Kansas with operating capacity of 9 MBbl/d; |
• | six natural gas liquids storage facilities in Oklahoma, Kansas and Texas with operating storage capacity of approximately 23.2 MMBbl; |
• | approximately 840 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 200 MBbl/d; |
• | approximately 3,500 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with approximately 708 MBbl/d of peak transportation capacity; |
• | eight natural gas liquids product terminals in Missouri, Nebraska, Iowa and Illinois; and |
• | above- and below-ground storage facilities associated with its FERC-regulated natural gas liquids pipeline operations in Iowa, Illinois, Nebraska and Kansas with combined operating capacity of approximately 978 MBbl. |
ONEOK Partners’ storage includes five underground natural gas storage facilities in Oklahoma, three underground natural gas storage facilities in Kansas and three underground natural gas storage facilities in Texas. One of its natural gas storage facilities in Kansas has been idle since 2001. In compliance with a KDHE order, ONEOK Partners began injecting brine into that facility in the first quarter 2007 and completed injection at the end of 2012 in order to ensure the long-term integrity of the idled facility. Monitoring of the facility and review of the data for the geo-engineering studies are ongoing, in compliance with a KDHE order while ONEOK Partners evaluates the alternatives for the facility. Following the testing of the gathered data, ONEOK Partners expects that the facility will be returned to storage service, although most likely for a product other than natural gas. The return to service will require additional actions and KDHE approval. It is possible, however, that testing could reveal that it is not safe to return the facility to service or that the KDHE will not grant the required permits to resume service.
As discussed further in “Growth Projects” in ONEOK Partners segment’s discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, we also are constructing or plan to construct the following assets:
• | approximately 270 miles of natural gas gathering pipelines in the Rocky Mountain region; |
• | three natural gas processing plants with approximately 300 MMcf/d of combined processing capacity in the Rocky Mountain region; |
• | one natural gas processing plant with approximately 200 MMcf/d of processing capacity in the Mid-Continent region; |
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• | approximately 600 miles of FERC-regulated natural gas liquids gathering pipelines from the Williston Basin to the Overland Pass Pipeline with approximately 135 MBbl/d of initial capacity; |
• | approximately 540 miles of FERC-regulated natural gas liquids distribution pipelines from Medford, Oklahoma, to Mont Belvieu, Texas, with approximately 193 MBbld of initial capacity; |
• | two natural gas liquids fractionators with approximately 150 MBbl/d of combined operating capacity that will be located in Texas; and |
• | one ethane/propane splitter with the capability of producing approximately 32 MBbl/d of purity ethane and approximately 8 MBbl/d of propane that will be located in Texas. |
Utilization - The utilization rates for ONEOK Partners’ various assets for 2012 and 2011 were as follows:
• | natural gas processing plants were approximately 69 percent and 71 percent utilized, respectively; |
• | natural gas pipelines were approximately 89 percent subscribed for each year, and storage facilities were fully subscribed both years; |
• | non-FERC-regulated natural gas liquids pipelines were approximately 68 percent and 71 percent subscribed, respectively; |
• | average contracted natural gas liquids storage volumes were approximately 60 percent and 63 percent of storage capacity, respectively; |
• | natural gas liquids fractionators were approximately 89 percent utilized in both years; |
• | FERC-regulated natural gas liquids gathering pipelines were approximately 99 percent and 97 percent utilized, respectively; and |
• | FERC-regulated natural gas liquids distribution pipelines were approximately 65 percent utilized in each year. |
ONEOK Partners calculates utilization on its assets using a weighted-average approach, adjusting for the dates that assets were placed in service. The utilization rate of ONEOK Partners’ fractionation facilities reflects leased capacity and the approximate proportional capacity associated with ONEOK Partner’s ownership interests.
Natural Gas Distribution
Property - We own approximately 19,000 miles of pipeline and other natural gas distribution facilities in Oklahoma; approximately 13,000 miles of pipeline and other natural gas distribution facilities in Kansas; and approximately 10,000 miles of pipeline and other natural gas distribution facilities in Texas. In addition, we have 39.3 Bcf of natural gas storage capacity under lease with maximum withdrawal capacity of approximately 1.0 Bcf/d.
Energy Services
Property - Our total natural gas storage capacity under lease is 71.5 Bcf, with maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.3 Bcf/d. At December 31, 2012, our natural gas transportation capacity was 1.0 Bcf/d, of which 1.0 Bcf/d was contracted under long-term natural gas transportation contracts. Our contracted storage and transportation capacity connects major supply and demand centers throughout the United States and into Canada. We have 20 different storage leases throughout the United States.
Other
Property - We own the 17-story ONEOK Plaza office building, with approximately 517,000 square feet of net rentable space, and an associated parking garage.
ITEM 3. LEGAL PROCEEDINGS
Gas Index Pricing Litigation: We, ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending, either individually or together, against the following lawsuits that claim damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others: Sinclair Oil Corporation v. ONEOK Energy Services Corporation, L.P., et al. (filed in the United States District Court for the District of Wyoming in September 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Reorganized FLI, Inc. (formerly J.P. Morgan Trust Company) v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte County, Kansas, in October 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Learjet, Inc., et al. v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte, Kansas, in November 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., et al. (filed in the District Court of Denver County, Colorado, in May 2006, transferred to MDL-1566 in the United States District Court for the District
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of Nevada); Arandell Corporation, et al. v. Xcel Energy, Inc., et al. (filed in the Circuit Court for Dane County, Wisconsin, in December 2006, transferred to MDL-1566 in the United States District Court for the District of Nevada); Heartland Regional Medical Center, et al. v. ONEOK, Inc., et al. (filed in the Circuit Court of Buchanan County, Missouri, in March 2007, transferred to MDL-1566 in the United States District Court for the District of Nevada); NewPage Wisconsin System v. CMS Energy Resource Management Company, et al. (filed in the Circuit Court for Wood County, Wisconsin, in March 2009, transferred to MDL-1566 in the United States District Court for the District of Nevada and now consolidated with the Arandell case). In each of these lawsuits, the plaintiffs allege that we, OESC and one other affiliate and approximately ten other energy companies and their affiliates engaged in an illegal scheme to inflate natural gas prices by providing false information to gas price index publications. All of the complaints arise out of a CFTC investigation into and reports concerning false gas price index-reporting or manipulation in the energy marketing industry during the years from 2000 to 2002.
On July 18, 2011, the trial court granted judgments in favor of ONEOK, Inc., OESC and other unaffiliated entities in the following cases: Reorganized FLI, Learjet, Arandell, Heartland, and NewPage. A final judgment in favor of all defendants was also granted in the Breckenridge case. The court also granted a final judgment in favor of OESC on all state law claims asserted in the Sinclair case. The plaintiffs in those cases case have appealed the judgments entered by the trial court to the United States Court of Appeals for the Ninth Circuit. All of the appeals have been consolidated for briefing purposes by the Ninth Circuit. On August 18, 2011, the trial court entered an order approving a stipulation by the plaintiffs and our affiliate, Kansas Gas Marketing Company (“KGMC”), for a dismissal without prejudice of the plaintiffs’ claims against KGMC in the Learjet and Heartland cases. On October 19, 2012, oral argument on the appeal was heard by the Ninth Circuit and a decision will be made by the Court at a later date.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
In June 2012, we completed a two-for-one split of our common stock. We have adjusted all share and per-share amounts contained herein to be presented on a post-split basis.
MARKET INFORMATION AND HOLDERS
Our common stock is listed on the NYSE under the trading symbol “OKE.” The corporate name ONEOK is used in newspaper stock listings. The following table sets forth the high and low closing prices of our common stock for the periods indicated:
Year Ended December 31, 2012 | Year Ended December 31, 2011 | |||||||||||||||
High | Low | High | Low | |||||||||||||
First Quarter | $ | 44.40 | $ | 40.22 | $ | 33.44 | $ | 27.69 | ||||||||
Second Quarter | $ | 43.98 | $ | 39.49 | $ | 37.00 | $ | 32.12 | ||||||||
Third Quarter | $ | 48.31 | $ | 42.26 | $ | 37.98 | $ | 29.66 | ||||||||
Fourth Quarter | $ | 49.39 | $ | 42.07 | $ | 43.35 | $ | 32.10 | ||||||||
At February 19, 2013, there were 14,792 holders of record of our 204,994,065 outstanding shares of common stock.
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DIVIDENDS
The following table sets forth the quarterly dividends declared and paid per share of our common stock during the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
First Quarter | $ | 0.305 | $ | 0.26 | $ | 0.22 | ||||||
Second Quarter | $ | 0.305 | $ | 0.26 | $ | 0.22 | ||||||
Third Quarter | $ | 0.33 | $ | 0.28 | $ | 0.23 | ||||||
Fourth Quarter | $ | 0.33 | $ | 0.28 | $ | 0.24 | ||||||
Total | $ | 1.27 | $ | 1.08 | $ | 0.91 | ||||||
In January 2013, we declared a dividend of $0.36 per share ($1.44 per share on an annualized basis) which was paid on February 14, 2013, to shareholders of record as of January 31, 2013.
ISSUER PURCHASES OF EQUITY SECURITIES
The following table sets forth information relating to our purchases of our common stock for the periods shown:
Period | Total Number of Shares Purchased (a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Be Purchased Under the Plans or Programs | ||||||||||||
October 1-31, 2012 | 300 | $ | 8.44 | — | ||||||||||||
November 1-30, 2012 | 2,000 | $ | 8.44 | — | ||||||||||||
December 1-31, 2012 | 400 | $ | 8.44 | — | ||||||||||||
Total | 2,700 | $ | 8.44 | — | $ | 300,000,000 | (b) | |||||||||
(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan.
(b) - The maximum approximate dollar value of shares that may yet be purchased pursuant to our approximately $750 million stock repurchase program that was announced on October 21, 2010, subject to the limitation that purchases will not exceed $300 million in any one calendar year. The program will terminate upon the completion of the repurchase of $750 million of common stock or on December 31, 2013, whichever occurs first.
EMPLOYEE STOCK AWARD PROGRAM
Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share. Shares issued to employees under this program during 2012 totaled 42,467, and compensation expense related to the Employee Stock Award Plan was not material. Shares issued to employees under this program during 2011 totaled 295,694, and compensation expense related to the Employee Stock Award Plan was $16.0 million. For 2010, the number of shares issued under this program was not material.
The total number of shares of our common stock available for issuance under this program is 900,000. The shares issued under this program have not been registered under the Securities Act, in reliance upon the position taken by the SEC (see Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not require registration under the Securities Act. See Note L of the Notes to Consolidated Financial Statements in this Annual Report for additional information.
PERFORMANCE GRAPH
The following performance graph compares the performance of our common stock with the S&P 500 Index, the S&P Utilities Index and a ONEOK Peer Group during the period beginning on December 31, 2007, and ending on December 31, 2012. The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.
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Value of $100 Investment Assuming Reinvestment of Dividends
at December 31, 2007, and at the End of Every Year Through December 31, 2012,
Among ONEOK, Inc., the S&P 500 Index, the S&P Utilities Index and a ONEOK Peer Group
Cumulative Total Return | ||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||
2008 | 2009 | 2010 | 2011 | 2012 | ||||||||||||||||
ONEOK, Inc. | $ | 67.50 | $ | 108.93 | $ | 140.93 | $ | 227.08 | $ | 230.58 | ||||||||||
S&P 500 Index | $ | 63.01 | $ | 79.69 | $ | 91.71 | $ | 93.62 | $ | 108.59 | ||||||||||
S&P Utilities Index (a) | $ | 71.01 | $ | 79.48 | $ | 83.84 | $ | 100.57 | $ | 101.83 | ||||||||||
ONEOK Peer Group (b) | $ | 81.32 | $ | 105.04 | $ | 127.06 | $ | 152.75 | $ | 158.02 | ||||||||||
(a) - The Standard & Poors Utilities Index is comprised of the following companies: AES Corp.; AGL Resource, Inc.; Ameren Corp.; American Electric Power Co., Inc.; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Edison International; Entergy Corp.; Exelon Corp.; FirstEnergy Corp.; Integrys Energy Group, Inc.; NextEra Energy, Inc.; NiSource, Inc.; Northeast Utilities; NRG Energy, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Public Service Enterprise Group, Inc.; SCANA Corp.; Sempra Energy; Southern Co.; TECO Energy, Inc.; Wisconsin Energy Corp.; and Xcel Energy, Inc. | ||||||||||||||||||||
(b) - The ONEOK Peer Group is comprised of the following companies: AGL Resources, Inc.; Atmos Energy Corp.; Centerpoint Energy, Inc.; DCP Midstream Partners, L.P.; Enbridge, Inc.; Enterprise Products Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan Energy, L.P.; National Fuel Gas Co.; New Jersey Resources Corp.; NiSource, Inc.; OGE Energy Corp.; Piedmont Natural Gas Company, Inc.; Sempra Energy; Spectra Energy Corp.; Southwest Gas Corp.; TransCanada Corp.; UGI Corp.; Vectren Corp.; WGL Holdings, Inc.; and Wisconsin Energy Corp. | ||||||||||||||||||||
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ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for each of the periods indicated:
Years Ended December 31, | ||||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
(Millions of dollars except per share amounts) | ||||||||||||||||||||
Revenues | $ | 12,632.6 | $ | 14,805.8 | $ | 12,678.8 | $ | 10,805.8 | $ | 15,514.3 | ||||||||||
Income from continuing operations | $ | 729.3 | $ | 757.5 | $ | 540.1 | $ | 483.7 | $ | 595.0 | ||||||||||
Income from continuing operations attributable to ONEOK | $ | 346.3 | $ | 358.4 | $ | 333.4 | $ | 297.9 | $ | 306.4 | ||||||||||
Net income attributable to ONEOK | $ | 360.6 | $ | 360.6 | $ | 334.6 | $ | 305.5 | $ | 311.9 | ||||||||||
Total assets | $ | 15,855.3 | $ | 13,696.6 | $ | 12,499.2 | $ | 12,827.7 | $ | 13,126.1 | ||||||||||
Long-term debt, including current maturities | $ | 6,526.2 | $ | 4,893.9 | $ | 4,329.8 | $ | 4,602.2 | $ | 4,230.8 | ||||||||||
Earnings per share - continuing operations | ||||||||||||||||||||
Basic | $ | 1.68 | $ | 1.71 | $ | 1.57 | $ | 1.41 | $ | 1.47 | ||||||||||
Diluted | $ | 1.64 | $ | 1.67 | $ | 1.55 | $ | 1.40 | $ | 1.45 | ||||||||||
Earnings per share - total | ||||||||||||||||||||
Basic | $ | 1.75 | $ | 1.72 | $ | 1.57 | $ | 1.45 | $ | 1.49 | ||||||||||
Diluted | $ | 1.71 | $ | 1.68 | $ | 1.55 | $ | 1.44 | $ | 1.47 | ||||||||||
Dividends declared per common share | $ | 1.27 | $ | 1.08 | $ | 0.91 | $ | 0.82 | $ | 0.78 | ||||||||||
The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report. All prior periods presented have been recast to reflect the discontinued operations. See Note B of the Notes to Consolidated Financial Statements in this Annual Report for additional information on our discontinued operations.
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and the Notes to Consolidated Financial Statements in this Annual Report.
RECENT DEVELOPMENTS
The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us. Please refer to the “Financial Results and Operating Information,” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operation and our consolidated financial statements and Notes to Consolidated Financial Statements for additional information.
Growth Projects - Crude oil and natural gas producers continue to drill aggressively in crude oil and NGL-rich areas, and related development activities continue to progress in many regions where ONEOK Partners has operations. ONEOK Partners expects continued development of the crude oil and natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region. In response to this increased production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, ONEOK Partners is investing approximately $4.7 billion to $5.3 billion in new capital projects between 2011 and 2015 to meet the needs of crude oil and natural gas producers and processors in the Williston Basin, the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas. In addition, ONEOK Partners is investing in NGL infrastructure in the Rocky Mountain, Mid-Continent and Gulf Coast regions. These assets will enhance ONEOK Partners’ ability to distribute NGL products to meet the increasing petrochemical industry and NGL export demand. The execution of these capital investments aligns with ONEOK Partners’ focus to grow fee-based earnings. Acreage dedications and supply commitments from natural gas producers and processors in regions associated with ONEOK Partners’ growth projects will provide incremental and long-term fee-based earnings and cash flows.
See discussion of ONEOK Partners’ growth projects in the “Financial Results and Operating Information” section for our ONEOK Partners segment.
Stock Split - In June 2012, we completed a two-for-one split of our common stock. We have adjusted all share and per-share amounts contained herein, to be presented on a post-split basis.
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Stock Repurchase Program - In September 2012, we completed an accelerated share repurchase agreement in which we repurchased approximately 3.4 million shares of our common stock for $150 million.
Our three-year stock repurchase program was authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock, subject to the limitation that purchases will not exceed $300 million in any one calendar year. Following our $150 million repurchase in September 2012 and our $300 million repurchase in 2011, an additional $300 million may yet be purchased pursuant to our three-year repurchase program.
Dividends/Distributions - During 2012, we paid dividends totaling $1.27 per share, an increase of approximately 18 percent over the $1.08 per share paid during 2011. We declared a quarterly dividend of $0.36 per share ($1.44 per share on an annualized basis) in January 2013, an increase of approximately 18 percent over the $0.305 declared in January 2012. During 2012, ONEOK Partners paid cash distributions totaling $2.59 per unit, an increase of approximately 11 percent over the $2.325 per unit paid during 2011. ONEOK Partners paid total cash distributions to us in 2012 of $760.9 million, which includes $559.6 million resulting from our limited-partner interest and $201.3 million related to our general partner interest. A cash distribution from ONEOK Partners of $0.71 per unit ($2.84 per unit on an annualized basis) was declared in January 2013, an increase of approximately 16 percent over the $0.61 declared in January 2012.
Retail Marketing Sale - On February 1, 2012, we sold ONEOK Energy Marketing Company, our Natural Gas Distribution segment’s retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized an after-tax gain on the sale of approximately $13.5 million. The proceeds from the sale were used to reduce short-term borrowings. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report. All prior periods presented have been recast to reflect the discontinued operations.
Debt Issuances - In January 2012, we completed an underwritten public offering of senior notes generating net proceeds of approximately $693.9 million. In September 2012, ONEOK Partners completed an underwritten public offering of senior notes generating net proceeds of approximately $1.3 billion.
ONEOK Partners Equity Issuances - In March 2012, ONEOK Partners completed an underwritten public offering of 8.0 million common units and also sold 8.0 million common units to us in a private placement, generating total net proceeds of approximately $920 million. In conjunction with the issuances, we contributed approximately $19 million in order to maintain our 2-percent general partner interest.
ONEOK Partners entered into an Equity Distribution Agreement (the EDA) for the offer and sale from time to time of its common units up to an aggregate amount of $300 million. ONEOK Partners is under no obligation to offer common units under the EDA. ONEOK Partners intends to use the net proceeds from sales under the program for general partnership purposes.
See Note P for a discussion of ONEOK Partners’ issuance of common units and distributions to noncontrolling interests.
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FINANCIAL RESULTS AND OPERATING INFORMATION
Consolidated Operations
Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:
Variances | Variances | |||||||||||||||||||||||||
Years Ended December 31, | 2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||||||||
Financial Results | 2012 | 2011 | 2010 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
(Millions of dollars) | ||||||||||||||||||||||||||
Revenues | $ | 12,632.6 | $ | 14,805.8 | $ | 12,678.8 | $ | (2,173.2 | ) | (15 | )% | $ | 2,127.0 | 17 | % | |||||||||||
Cost of sales and fuel | 10,281.7 | 12,425.4 | 10,616.6 | (2,143.7 | ) | (17 | )% | 1,808.8 | 17 | % | ||||||||||||||||
Net margin | 2,350.9 | 2,380.4 | 2,062.2 | (29.5 | ) | (1 | )% | 318.2 | 15 | % | ||||||||||||||||
Operating costs | 909.0 | 908.3 | 830.9 | 0.7 | — | % | 77.4 | 9 | % | |||||||||||||||||
Depreciation and amortization | 335.8 | 312.2 | 307.2 | 23.6 | 8 | % | 5.0 | 2 | % | |||||||||||||||||
Goodwill impairment | 10.3 | — | — | 10.3 | 100 | % | — | — | % | |||||||||||||||||
Gain (loss) on sale of assets | 6.7 | (1.0 | ) | 18.6 | 7.7 | * | (19.6 | ) | * | |||||||||||||||||
Operating income | $ | 1,102.5 | $ | 1,158.9 | $ | 942.7 | $ | (56.4 | ) | (5 | )% | $ | 216.2 | 23 | % | |||||||||||
Equity earnings from investments | $ | 123.0 | $ | 127.2 | $ | 101.9 | $ | (4.2 | ) | (3 | )% | $ | 25.3 | 25 | % | |||||||||||
Interest expense | $ | (302.3 | ) | $ | (297.0 | ) | $ | (292.2 | ) | $ | 5.3 | 2 | % | $ | 4.8 | 2 | % | |||||||||
Net income | $ | 743.5 | $ | 759.7 | $ | 541.3 | $ | (16.2 | ) | (2 | )% | $ | 218.4 | 40 | % | |||||||||||
Net income attributable to noncontrolling interests | $ | 382.9 | $ | 399.2 | $ | 206.7 | $ | (16.3 | ) | (4 | )% | $ | 192.5 | 93 | % | |||||||||||
Net income attributable to ONEOK | $ | 360.6 | $ | 360.6 | $ | 334.6 | $ | — | — | % | $ | 26.0 | 8 | % | ||||||||||||
Capital expenditures | $ | 1,866.2 | $ | 1,336.1 | $ | 582.7 | $ | 530.1 | 40 | % | $ | 753.4 | * | |||||||||||||
* Percentage change is greater than 100 percent.
2012 vs, 2011 - Revenues for 2012, compared with the prior year, decreased due to lower net realized natural gas and NGL product prices, offset partially by higher natural gas and NGL sales volumes from ONEOK Partners’ completed capital projects. The increase in natural gas supply resulting from the development of nonconventional resource areas in North America and a warmer than normal winter have caused lower natural gas prices and narrower natural gas location and seasonal price differentials in the markets we serve. NGL prices, particularly ethane and propane, also decreased in 2012 due primarily to increased NGL production growth from the development of NGL-rich areas. Propane prices also were affected by a warmer than normal winter. During the second half of 2012, NGL location price differentials also narrowed due to strong production growth, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers.
Operating income for 2012 reflects higher results from our ONEOK Partners and Natural Gas Distribution segments, offset by lower results from our Energy Services segment. Our ONEOK Partners segment’s results benefited from higher volumes from completed capital projects in its natural gas gathering and processing and natural gas liquids businesses. These increases were offset partially by less favorable NGL price differentials and lower NGL transportation capacity available for optimization activities in ONEOK Partners natural gas liquids business. Additionally, the increase was offset by higher compression and processing costs and lower realized natural gas and NGL product prices, particularly ethane and propane, in its natural gas gathering and processing business. Our Natural Gas Distribution segment benefited from new rates in all three states where it has operations and lower operating costs.
These increases were offset by lower margins in our Energy Services segment due primarily to the impact of lower realized natural gas prices due to narrower natural gas seasonal and location price differentials and the impact of our hedging strategies on our storage and marketing and transportation margins and a nonrecurring goodwill impairment charge in the first quarter 2012.
Operating costs for 2012 were relatively unchanged due primarily to the increased costs associated with our ONEOK Partners segment’s expanding operations as a result of several internal growth projects that were placed in service and scheduled maintenance costs being offset by lower employee-related costs in our Natural Gas Distribution and Energy Services segments.
Interest expense increased in 2012, compared with the prior year, primarily as a result of higher interest costs from ONEOK’s $700 million debt issuance in January 2012 and ONEOK Partners’ $1.3 billion debt issuance in September 2012, offset
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partially by higher capitalized interest associated with ONEOK Partners’ growth projects in its natural gas gathering and processing and natural gas liquids businesses.
Net income attributable to noncontrolling interests reflects primarily the earnings of ONEOK Partners attributable to the portion of ONEOK Partners that we do not own.
Capital expenditures increased for 2012, compared with 2011, due primarily to the growth projects in ONEOK Partners’ natural gas liquids business.
2011 vs. 2010 - NGL and condensate prices were higher while natural gas prices decreased during 2011, compared with 2010. These changes in commodity prices had a direct impact on our revenues and cost of sales and fuel.
Operating income increased 23 percent in 2011 reflecting higher results from our ONEOK Partners segment, offset partially by lower operating income from our Natural Gas Distribution and Energy Services segments. Our ONEOK Partners segment’s operating income significantly increased due primarily to more favorable NGL location differentials and higher NGL volumes gathered and fractionated, offset partially by the deconsolidation of Overland Pass Pipeline in September 2010 in its natural gas liquids business and lower natural gas transportation margins due to narrower natural gas price location differentials in its natural gas pipelines business.
Our Natural Gas Distribution segment’s operating income decreased 12 percent in 2011 due to increased operating costs.
Our Energy Services segment’s operating income decreased significantly in 2011 due primarily to lower transportation, storage and marketing margins, net of hedging activities.
Operating costs increased in 2011 due primarily to higher short-term incentive and share-based compensation and other labor and benefit costs for all segments and higher materials and outside services expenses in our ONEOK Partners segment.
Gain (loss) on sale of assets decreased from 2010, which reflected a $16.3 million gain on the sale of a 49-percent interest of Overland Pass Pipeline Company.
Equity earnings from investments increased in 2011, compared with 2010, due to the impact of accounting for Overland Pass Pipeline Company as an equity method investment beginning in September 2010 and increased contracted capacity on Northern Border Pipeline.
Net income attributable to noncontrolling interests reflects higher earnings in our ONEOK Partners segment during 2011 compared with 2010.
Capital expenditures increased during 2011 due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.
More information regarding our results of operations is provided in the following discussion of operating results for each of our segments.
ONEOK Partners
Growth Projects - Bakken Crude Express Pipeline - In April 2012, ONEOK Partners announced plans to build the Bakken Crude Express Pipeline. ONEOK Partners held an open season process that provided potential shippers with the opportunity to execute long-term transportation contracts in exchange for priority transportation service. In November 2012, ONEOK Partners elected not to proceed with plans to construct the Bakken Crude Express Pipeline due to insufficient long-term transportation commitments during the open season.
Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business is investing approximately $2.1 billion to $2.3 billion in growth projects in the Williston Basin and Cana-Woodford Shale areas that will enable ONEOK Partners to meet the rapidly growing needs of natural gas producers in those areas.
Williston Basin Processing Plants and related projects - ONEOK Partners’ projects in this basin include five 100 MMcf/d natural gas processing facilities: the Garden Creek, Garden Creek II and Garden Creek III plants located in eastern McKenzie County, North Dakota, and the Stateline I and II plants located in western Williams County, North Dakota. ONEOK Partners has acreage dedications of approximately 3.1 million acres supporting these plants. In addition, ONEOK Partners is expanding
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and upgrading its existing natural gas gathering and compression infrastructure and also adding new well connections associated with these plants. The Garden Creek plant was placed in service in December 2011 and together with the related infrastructure cost approximately $360 million, excluding AFUDC. ONEOK Partners expects construction costs, excluding AFUDC, for the Garden Creek II plant will be $310 million to $345 million, and for the Garden Creek III plant will be approximately $325 million to $360 million. The Garden Creek II and Garden Creek III plants are expected to be in service during the third quarter 2014 and the first quarter 2015, respectively. Together, the Stateline I and II plants and related infrastructure projects are expected to cost approximately $560 million to $660 million, excluding AFUDC. The 100 MMcf/d Stateline I natural gas processing facility was placed into service in September 2012, and the 100 MMcf/d Stateline II natural gas processing facility is expected to be in service during the first quarter 2013.
ONEOK Partners plans to invest $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota. The new system will gather and deliver natural gas from producers in the Williston Basin to both of ONEOK Partners’ Stateline natural gas processing facilities in western Williams County, North Dakota. ONEOK Partners has secured long-term supply commitments from producers for this new system, which are structured with POP and fee-based contractual components. This project is expected to be completed in the third quarter 2013.
ONEOK Partners expects that these capital projects will continue to provide additional revenues from POP and fee-based contracts as they are completed. ONEOK Partners expects its commodity price exposure to increase, particularly to NGL and natural gas prices, as equity volumes increase under its natural gas gathering and processing business’ POP contracts with its customers in the Williston Basin. ONEOK Partners uses derivative instruments to mitigate its sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for its share of volumes.
Cana-Woodford Shale projects - ONEOK Partners plans to invest approximately $340 million to $360 million to construct a new 200 MMcf/d natural gas processing facility, the Canadian Valley plant, and related infrastructure in the Cana-Woodford Shale in Canadian County, Oklahoma, in close proximity to its existing natural gas transportation and natural gas liquids gathering pipelines. The additional natural gas processing infrastructure is necessary to accommodate increased production of NGL-rich natural gas in the Cana-Woodford Shale where ONEOK Partners has substantial acreage dedications from active producers. The new Canadian Valley plant is expected to cost approximately $190 million, excluding AFUDC, and is expected to be in service in the first quarter 2014. The related additional infrastructure is expected to cost approximately $160 million, excluding AFUDC, and is expected to increase ONEOK Partners’ capacity to gather and process natural gas to approximately 390 MMcf/d in the Cana-Woodford Shale.
In both the Williston Basin and Cana-Woodford Shale project areas, nearly all of the new gas production is from horizontally drilled and completed wells. Horizontal wells drilled in the Williston Basin are justified primarily by crude-oil economics, which are currently very favorable. These wells tend to produce at higher initial volumes resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. These wells are expected to have long productive lives. ONEOK Partners expects the routine growth capital needed to connect to new wells and expand its infrastructure to increase compared with its historical levels of routine growth capital.
Natural gas liquids business - The growth strategy in ONEOK Partners’ natural gas liquids business is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other unconventional resource areas from the Rocky Mountain region through the Mid-Continent region into Texas. Increasing crude oil, natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required ONEOK Partners to make additional capital investments to expand its infrastructure to bring these commodities from supply basins to market. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly over the next five years, and international demand for propane is expected to impact positively the NGL market in the future.
ONEOK Partners’ natural gas liquids business is investing approximately $2.6 billion to $3.0 billion in NGL-related projects through 2015. These investments will accommodate the transportation and fractionation of growing NGL supply from shale and other resource development areas across ONEOK Partners’ asset base and alleviate infrastructure constraints between the Mid-Continent and Gulf Coast market centers to meet increasing petrochemical industry and NGL export demand in the Gulf Coast. Over time, these growing fee-based NGL volumes are expected to fill much of its pipeline capacity used historically to capture the NGL price differentials between the two market centers. During the second half of 2012, NGL price differentials narrowed between the Mid-Continent and Gulf Coast market centers. ONEOK Partners expects these narrow NGL price differentials to continue as new fractionators and pipelines, including ONEOK Partners’ growth projects discussed below, continue to alleviate constraints between the two market centers.
Sterling III Pipeline - ONEOK Partners is in the process of constructing a 540-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL products from the Mid-
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Continent to the Gulf Coast. The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, where the pipeline can gather unfractionated NGLs from the new natural gas processing plants that are being built as a result of increased drilling activity in these areas. The Sterling III Pipeline will have an initial capacity to transport up to 193 MBbl/d of production from ONEOK Partners’ natural gas liquids infrastructure at Medford, Oklahoma, to its storage and fractionation facilities in Mont Belvieu, Texas. ONEOK Partners has multi-year supply commitments from producers and natural gas processors for approximately 75 percent of the pipeline’s capacity. Installation of additional pump stations could expand the capacity of the pipeline to 250 MBbl/d. Following the receipt of all necessary permits and the acquisition of rights-of-way, construction is scheduled to begin in 2013, with an expected completion late this year.
The project also includes reconfiguration of its existing Sterling I and II pipelines, which distribute NGL products between the Mid-Continent and Gulf Coast natural gas liquids market centers, to transport either unfractionated NGLs or NGL products. The project costs for the new pipeline and reconfiguration projects are estimated to be $610 million to $810 million, excluding AFUDC.
MB-2 Fractionator - ONEOK Partners is constructing a new 75 MBbl/d fractionator, MB-2, near its storage facility in Mont Belvieu, Texas. Construction began in June 2011 and is expected to be completed in mid-2013. The cost of the new fractionator is estimated to be $300 million to $390 million, excluding AFUDC. ONEOK Partners has multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity.
MB-3 Fractionator - ONEOK Partners plans to construct a 75 MBbl/d fractionator, MB-3, near its storage facility in Mont Belvieu, Texas. In addition, ONEOK Partners plans to expand and upgrade its existing natural gas liquids gathering and pipeline infrastructure, including new connections to natural gas processing facilities and increasing the capacity of the Arbuckle and Sterling II natural gas liquids pipelines. The MB-3 fractionator and related infrastructure are expected to cost approximately $525 million to $575 million, excluding AFUDC. The MB-3 fractionator is expected to be completed in the fourth quarter 2014. Supply commitments from third-party natural gas processors are in various stages of negotiation.
Ethane/Propane Splitter - ONEOK Partners plans to construct a new 40 MBbl/d ethane/propane splitter at its Mont Belvieu storage facility to split ethane/propane mix into purity ethane in order to meet the growing needs of petrochemical customers. The facility will be capable of producing 32 MBbl/d of purity ethane and 8 MBbl/d of propane, and is expected to be in service during the second quarter 2014. The ethane/propane splitter is expected to cost approximately $45 million, excluding AFUDC.
Bakken NGL Pipeline and related projects - ONEOK Partners is constructing an approximately 600-mile natural gas liquids pipeline, the Bakken NGL Pipeline, to transport unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline. ONEOK Partners also announced plans to invest an additional $100 million to install additional pump stations on the Bakken NGL Pipeline to increase its capacity to 135 MBbl/d from an initial capacity of 60 MBbl/d. The unfractionated NGLs then will be delivered to ONEOK Partners’ existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Project costs for the new pipeline, including the expansion, are estimated to be $550 million to $650 million, excluding AFUDC. NGL supply commitments for the Bakken NGL Pipeline are anchored by NGL production from ONEOK Partners’ natural gas processing plants. The 12-inch diameter pipeline is expected to be in service during the first quarter 2013, and the expansion is expected to be completed in the third quarter 2014.
The unfractionated NGLs from the Bakken NGL Pipeline and other supply sources under development in the Rocky Mountain region will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline in which ONEOK Partners owns a 50-percent equity interest. These additions and expansions will increase the capacity of the Overland Pass Pipeline to 255 MBbl/d. ONEOK Partners’ anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.
Bushton Fractionator expansion - In September 2012, ONEOK Partners completed an expansion and upgrade to its existing NGL fractionation capacity at Bushton, Kansas, increasing capacity to 210 MBbl/d from 150 MBbl/d. This additional capacity is necessary to accommodate the volume growth from the Mid-Continent and Williston Basin. The project cost approximately $117 million, excluding AFUDC.
New NGL pipeline and modification of Hutchinson fractionation infrastructure - ONEOK Partners plans to invest approximately $140 million, excluding AFUDC, to construct a new 95-mile natural gas liquids pipeline that will connect its existing NGL fractionation and storage facilities in Hutchinson, Kansas, to similar facilities in Medford, Oklahoma. These projects also include related modifications to existing natural gas liquids fractionation infrastructure at Hutchinson, Kansas, to
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accommodate additional unfractionated NGLs produced in the Williston Basin. The pipeline and related modifications are expected to be in service during the first quarter 2015.
Cana-Woodford Shale and Granite Wash projects - ONEOK Partners constructed approximately 230 miles of natural gas liquids pipelines that expanded its existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. These pipelines expanded ONEOK Partners’ capacity to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. The pipelines are connected to three new third-party natural gas processing facilities and to three existing third-party natural gas processing facilities that were expanded. Additionally, ONEOK Partners installed additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d. These projects are expected to add, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to ONEOK Partners’ existing natural gas liquids gathering systems. These projects were placed in service in April 2012 and cost approximately $220 million, excluding AFUDC.
For a discussion of ONEOK Partners’ capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” on page 63.
Selected Financial Results and Operating Information - ONEOK Partners’ 2012 and 2011 operating results reflect the benefits from the following completed growth projects:
• | Stateline I natural gas processing plant, which was placed into service in September 2012; |
• | the expansion of the Bushton natural gas liquids fractionator, which was placed into service in September 2012; |
• | the expansion of its Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas, which was placed into service in April 2012; |
• | Garden Creek natural gas processing plant, which was placed into service December 2011; |
• | the expansion of its Sterling I natural gas liquids distribution pipeline, which was placed in service in the fourth quarter 2011; and |
• | the additional Gulf Coast natural gas liquids fractionation capacity made available by its 60 Mbl/d natural gas liquids fractionation agreement with Targa Resources Partners that began in the second quarter 2011. |
These projects increased natural gas volumes processed in the Williston Basin in its natural gas gathering and processing business and NGL volumes gathered, fractionated and sold in its natural gas liquids business. ONEOK Partners expects drilling activities and development of the reserves to continue in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Woodford Shale and Granite Wash areas in Oklahoma and Texas.
The following table sets forth certain selected financial results for our ONEOK Partners segment for the periods indicated:
Variances | Variances | |||||||||||||||||||||||||
Years Ended December 31, | 2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||||||||
Financial Results | 2012 | 2011 | 2010 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
(Millions of dollars) | ||||||||||||||||||||||||||
Revenues | $ | 10,182.2 | $ | 11,322.6 | $ | 8,675.9 | $ | (1,140.4 | ) | (10 | )% | $ | 2,646.7 | 31 | % | |||||||||||
Cost of sales and fuel | 8,540.4 | 9,745.2 | 7,531.0 | (1,204.8 | ) | (12 | )% | 2,214.2 | 29 | % | ||||||||||||||||
Net margin | 1,641.8 | 1,577.4 | 1,144.9 | 64.4 | 4 | % | 432.5 | 38 | % | |||||||||||||||||
Operating costs | 482.5 | 459.4 | 403.5 | 23.1 | 5 | % | 55.9 | 14 | % | |||||||||||||||||
Depreciation and amortization | 203.1 | 177.5 | 173.7 | 25.6 | 14 | % | 3.8 | 2 | % | |||||||||||||||||
Gain (loss) on sale of assets | 6.7 | (1.0 | ) | 18.6 | 7.7 | * | (19.6 | ) | * | |||||||||||||||||
Operating income | $ | 962.9 | $ | 939.5 | $ | 586.3 | $ | 23.4 | 2 | % | $ | 353.2 | 60 | % | ||||||||||||
Equity earnings from investments | $ | 123.0 | $ | 127.2 | $ | 101.9 | $ | (4.2 | ) | (3 | )% | $ | 25.3 | 25 | % | |||||||||||
Interest expense | $ | (206.0 | ) | $ | (223.1 | ) | $ | (204.3 | ) | $ | (17.1 | ) | (8 | )% | $ | 18.8 | 9 | % | ||||||||
Capital expenditures | $ | 1,560.5 | $ | 1,063.4 | $ | 352.7 | $ | 497.1 | 47 | % | $ | 710.7 | * | |||||||||||||
* Percentage change is greater than 100 percent.
2012 vs. 2011 - Revenues and cost of sales decreased for 2012 due to lower natural gas and NGL product prices and narrower NGL product price differentials, offset partially by higher natural gas and NGL sales volumes from the ONEOK Partners segment’s completed capital projects. The increase in natural gas supply resulting from development of nonconventional resource areas in North America and a warmer than normal winter have caused lower natural gas prices and narrower natural
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gas location and seasonal price differentials in the markets it serves. NGL prices. particularly ethane and propane, also decreased in 2012 due primarily to increased NGL production growth from the development of NGL-rich resource areas. Propane prices also were affected by a warmer than normal winter. During the second half of 2012, NGL location price differentials also narrowed due to the strong production growth, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers.
The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential of ethane and natural gas may influence the volume of NGLs recovered from natural gas processing plants. When economic conditions warrant, natural gas processors may elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the residue natural gas stream sold at the tailgate of natural gas processing plants. Price differentials between ethane and natural gas resulted in periods of ethane rejection in the Mid-Continent and Rocky Mountain regions during 2012. Ethane rejection did not have a material impact on ONEOK Partners’ financial results in 2012. We expect lower natural gas liquids volumes in ONEOK Partners’ natural gas liquids business as a result of widespread and prolonged ethane rejection in 2013 that is expected to have a significant impact on our financial results. We do not expect prolonged ethane rejection to continue in 2014.
Net margin increased primarily as a result of the following:
• | an increase of $131.5 million due to volume growth in the Williston Basin from ONEOK Partners’ new Garden Creek and Stateline I natural gas processing plants and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees in ONEOK Partners’ natural gas gathering and processing business; |
• | an increase of $101.5 million related to higher NGL volumes gathered and fractionated across ONEOK Partners’ systems related to completion of certain growth projects and contract renegotiations for higher fees associated with ONEOK Partners’ NGL exchange services activities; and |
• | an increase of $13.1 million due to higher natural gas liquids storage margins as a result of contract renegotiations at higher fees in ONEOK Partners’ natural gas liquids business; offset partially by |
• | a decrease of $91.2 million in optimization and marketing margins in ONEOK Partners’ natural gas liquids business, which resulted from a $94.6 million decrease due to narrower NGL price differentials and reduced transportation capacity available for optimization activities, as an increasing portion of its transportation capacity between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers was utilized by its exchange services activities to produce fee-based earnings. This decrease was offset partially by a $3.5 million increase in ONEOK Partners’ marketing activities that benefited from higher natural gas liquids truck and rail volumes; |
• | a decrease of $38.1 million due primarily to higher compression costs and less favorable contract terms associated with volume growth in the Williston Basin in ONEOK Partners’ natural gas gathering and processing business; |
• | a decrease of $31.4 million due to lower net realized natural gas and NGL prices, particularly in ethane and propane, in ONEOK Partners’ natural gas gathering and processing business; and |
• | a decrease of $5.9 million due to lower natural gas volumes gathered in the Powder River Basin as a result of continued declines in coal-bed methane production. |
Operating costs increased for 2012, compared with the prior year, as a result of the growth of ONEOK Partners operations and reflect the following:
• | an increase of $27.3 million from higher materials and supplies, and outside services expenses, including costs associated with scheduled maintenance at ONEOK Partners’ existing facilities, and higher ad valorem taxes; offset partially by |
• | a decrease of $3.7 million due primarily to $9.0 million decrease of labor and employee-related costs associated with incentive and benefit plans, offset partially by a $5.3 million increase in other labor and employee-related costs due to the growth of operations in its natural gas gathering and processing and natural gas liquids businesses. |
Depreciation and amortization increased due primarily to the higher depreciation expense associated with ONEOK Partners’ completed capital projects, which includes the completion of its Garden Creek and Stateline I natural gas processing plants, well connections and infrastructure projects supporting the volume growth in the Williston Basin.
Equity earnings from ONEOK Partners’ investments decreased due primarily to increased maintenance expenses at Northern Border Pipeline.
Capital expenditures increased for 2012, compared with the prior year, due primarily to the growth projects in ONEOK Partners’ natural gas liquids business, offset partially by timing of expenditures on growth projects in ONEOK Partners’ natural gas gathering and processing business.
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2011 vs. 2010 - Net margin increased due primarily to the following:
• | an increase of $363.6 million in optimization and marketing margins in ONEOK Partners’ natural gas liquids business due primarily to the following: |
– | an increase of $335.2 million from more favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers; and |
– | an increase of $28.4 from higher marketing volumes and more favorable margins on NGL products marketed; |
• | an increase of $32.6 million due to higher net realized NGL and condensate prices in ONEOK Partners’ natural gas gathering and processing business; |
• | an increase of $32.5 million from higher NGL volumes gathered and fractionated in Texas and the Mid-Continent and Rocky Mountain regions, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations for higher fees associated with ONEOK Partners’ NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties in its natural gas liquids business; |
• | an increase of $26.4 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane and higher isomerization volumes in ONEOK Partners’ natural gas liquids business; |
• | an increase of $19.4 million due to higher natural gas volumes processed in the Williston Basin and western Oklahoma resulting from increased drilling activity, offsetting reduced drilling activity in certain parts of Kansas and weather-related outages during the first quarter in ONEOK Partners’ natural gas gathering and processing business; |
• | an increase of $12.4 million due to higher storage margins as a result of contract renegotiations in ONEOK Partners’ natural gas liquids business; and |
• | an increase of $8.8 million due to favorable changes in contract terms in ONEOK Partners’ natural gas gathering and processing business; offset partially by |
• | a decrease of $42.8 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in ONEOK Partners’ natural gas liquids business; |
• | a decrease of $12.5 million from lower natural gas transportation margins due to narrower natural gas price location differentials that decreased contracted transportation capacity on Midwestern Gas Transmission and interruptible transportation volumes across ONEOK Partners’ pipelines in its natural gas pipelines business; and |
• | a decrease of $8.2 million due to lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity by producers in the Powder River Basin in ONEOK Partners’ natural gas gathering and processing business. |
Operating costs increased due primarily to the following:
• | an increase of $35.7 million in higher labor and employee-related costs associated with incentive and benefit plans, which includes higher share-based compensation costs resulting from common stock awarded to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price, affecting all of ONEOK Partners’ businesses; |
• | an increase of $9.4 million from higher materials and outside services expenses associated primarily with scheduled maintenance at fractionation, pipeline and storage facilities in ONEOK Partners’ natural gas liquids business; and |
• | an increase of $5.0 million due to higher ad valorem taxes associated with the completed capital projects in all of ONEOK Partners’ businesses; offset partially by |
• | a decrease of $5.4 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method of accounting in ONEOK Partners’ natural gas liquids business. |
Gain (loss) on sale of assets decreased due to the $16.3 million gain on the sale of a 49-percent interest of Overland Pass Pipeline Company recorded in 2010.
Equity earnings include Overland Pass Pipeline Company in ONEOK Partners’ natural gas liquids business, which it began accounting for under the equity method of accounting in September 2010. Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline in ONEOK Partners’ natural gas pipelines business. Northern Border Pipeline benefited from wider natural gas price location differentials between the markets it serves, which resulted in a significant increase in its capacity being sold in 2011.
Capital expenditures increased due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.
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Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which we contracted for all of OBPI’s rights, including all of the capacity of the Bushton Plant, reimbursing OBPI for all costs associated with the operation and maintenance of the Bushton Plant and its obligations under equipment leases covering portions of the Bushton Plant. On June 30, 2011, through a series of transactions, we sold OBPI to ONEOK Partners, and OBPI closed the purchase option and terminated the equipment leases. The total amount paid by ONEOK Partners to complete the transactions was approximately $94.2 million, which included the reimbursement to us of obligations related to the Processing and Services Agreement.
Selected Operating Information - The following table sets forth selected operating information for our ONEOK Partners segment for the periods indicated:
Operating Information | 2012 | 2011 | 2010 | |||||||||
Natural gas gathering and processing business (a) | ||||||||||||
Natural gas gathered (BBtu/d) | 1,119 | 1,030 | 1,067 | |||||||||
Natural gas processed (BBtu/d) (b) | 866 | 713 | 674 | |||||||||
NGL sales (MBbl/d) | 61 | 48 | 44 | |||||||||
Residue gas sales (BBtu/d) | 397 | 317 | 286 | |||||||||
Realized composite NGL net sales price ($/gallon) (c) | $ | 1.06 | $ | 1.08 | $ | 0.94 | ||||||
Realized condensate net sales price ($/Bbl) (c) | $ | 88.22 | $ | 82.56 | $ | 63.81 | ||||||
Realized residue gas net sales price ($/MMBtu) (c) | $ | 3.87 | $ | 5.47 | $ | 5.58 | ||||||
Realized gross processing spread ($/MMBtu) (c) | $ | 8.05 | $ | 8.17 | $ | 6.41 | ||||||
Natural gas pipelines business (a) | ||||||||||||
Natural gas transportation capacity contracted (MDth/d) | 5,366 | 5,373 | 5,616 | |||||||||
Transportation capacity subscribed (d) | 89 | % | 89 | % | 93 | % | ||||||
Average natural gas price | ||||||||||||
Mid-Continent region ($/MMBtu) | $ | 2.64 | $ | 3.88 | $ | 4.17 | ||||||
Natural gas liquids business | ||||||||||||
NGL sales (MBbl/d) | 572 | 497 | 457 | |||||||||
NGLs fractionated (MBbl/d) (e) | 574 | 537 | 512 | |||||||||
NGLs transported-gathering lines (MBbl/d) (a) (f) | 520 | 436 | 440 | |||||||||
NGLs transported-distribution lines (MBbl/d) (a) | 491 | 473 | 468 | |||||||||
Average Conway-to-Mont Belvieu OPIS average price differential - Ethane in ethane/propane mix ($/gallon) | $ | 0.17 | $ | 0.28 | $ | 0.10 | ||||||
(a) - For consolidated entities only.
(b) - Includes volumes processed at company-owned and third-party facilities.
(c) - Presented net of the impact of hedging activities and includes equity volumes only.
(d) - Prior periods have been recast to reflect current estimated capacity.
(e) - Includes volumes fractionated from company-owned and third-party facilities.
(f) - 2010 volume information includes 62 MBbl/d related to Overland Pass Pipeline Company, which was deconsolidated in September 2010.
2012 vs. 2011 - Natural gas gathered volumes increased in 2012, compared with the prior year, due to increased drilling activity in the Williston Basin and western Oklahoma, completion of additional natural gas gathering lines and compression to support ONEOK Partners’ new Garden Creek and Stateline I natural gas processing plants, offset partially by continued declines in coal-bed methane production in the Powder River Basin in Wyoming.
Low natural gas prices and the relatively higher crude oil and NGL prices compared with natural gas on a heating-value basis have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the Powder River Basin. The reduced development activities and natural production declines in the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects. A continued decline in volumes gathered in this area may reduce ONEOK Partners’ ability to recover the carrying value of its assets and equity investments in this area and could result in noncash charges to earnings.
The quantity and composition of NGLs received by ONEOK Partners’ natural gas gathering and processing business as payments under its various processing agreements continue to change as its new natural gas processing plants in the Williston Basin are placed in service. ONEOK Partners’ Garden Creek and Stateline I plants have the capability to recover ethane when economic conditions warrant but will not until ONEOK Partners’ natural gas liquids business’ Bakken NGL Pipeline is
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completed. The Bakken NGL Pipeline is expected to be completed in the first quarter 2013. As a result, the 2012 equity NGL volumes and realized composite NGL net sales price associated with its natural gas gathering and processing business are weighted more toward the relatively higher priced propane, iso-butane, normal butane and natural gasoline compared with the prior year. This has the effect of producing a higher NGL composite barrel realized price, while most individual NGL products prices are substantially lower this year compared with the prior year.
In November 2012, the FERC initiated a review of Viking Gas Transmission’s rates pursuant to Section 5 of the Natural Gas Act. The review is currently in process, and while the ultimate outcome cannot be predicted, it could result in a future reduction of rates. ONEOK Partners does not expect the ultimate outcome to impact materially its results of operations.
ONEOK Partners’ operating information above does not include its 50-percent interest in Northern Border Pipeline. Substantially all of Northern Border Pipeline’s long-haul transportation capacity has been contracted through March 2014. In September 2012, Northern Border Pipeline filed with the FERC a settlement with its customers to modify its transportation rates. In January 2013, the settlement was approved and the new rates became effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower, compared with previous rates, which is expected to reduce ONEOK Partners’ future equity earnings and cash distributions from Northern Border Pipeline.
NGLs gathered and fractionated increased due primarily to increased throughput from existing connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions. Increased NGL gathering capacity in the Mid-Continent region and Texas was made available through ONEOK Partners’ Cana-Woodford Shale and Granite Wash projects, which were placed in service in April 2012. Increased Gulf Coast NGL fractionation capacity was made available by the 60 Mbl/d fractionation services agreement with Targa Resources Partners that began in the second quarter 2011.
NGLs transported on distribution lines increased due primarily to the Sterling I pipeline expansion and higher volumes transported on ONEOK Partners’ natural gas liquids distribution pipelines between its Mid-Continent and Gulf Coast facilities to optimize the delivery of supply.
2011 vs. 2010 - Natural gas gathered decreased in 2011, compared with 2010, due to continued production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming and certain parts of Kansas, and weather-related outages in the first quarter 2011, offset partially by increased drilling activity in the Williston Basin and western Oklahoma.
Natural gas processed and residue gas sales increased in 2011, compared with 2010, due to an increase in drilling activity in the Williston Basin and western Oklahoma, offsetting reduced drilling activity and natural production declines in Kansas and weather-related outages in the first quarter 2011.
Natural gas transportation capacity contracted decreased due primarily to lower contracted capacity on Midwestern Gas Transmission due to narrower natural gas price location differentials between the markets we serve.
NGLs gathered and fractionated, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, increased due primarily to increased throughput through existing connections in Texas and the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions. In the second quarter 2011, additional Gulf Coast fractionation capacity became available through our 60 MBbl/d fractionation service agreement with Targa Resources Partners.
NGLs transported on distribution lines increased due primarily to increased volumes of NGL products transported on our North System pipeline to Midwest markets and our Sterling I pipeline expansion discussed above.
Natural Gas Distribution
On February 1, 2012, we sold ONEOK Energy Marketing Company, our retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized an after-tax gain on the sale of approximately $13.5 million. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report. All prior periods presented have been recast to reflect the discontinued operations.
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Selected Financial Results - The following table sets forth certain selected financial results for the continuing operations of our Distribution segment for the periods indicated:
Variances | Variances | |||||||||||||||||||||||||
Years Ended December 31, | 2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||||||||
Financial Results | 2012 | 2011 | 2010 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
(Millions of dollars) | ||||||||||||||||||||||||||
Gas sales | $ | 1,252.0 | $ | 1,492.5 | $ | 1,687.4 | $ | (240.5 | ) | (16 | )% | $ | (194.9 | ) | (12 | )% | ||||||||||
Transportation revenues | 88.8 | 90.9 | 91.5 | (2.1 | ) | (2 | )% | (0.6 | ) | (1 | )% | |||||||||||||||
Cost of gas | 620.2 | 869.5 | 1,062.5 | (249.3 | ) | (29 | )% | (193.0 | ) | (18 | )% | |||||||||||||||
Net margin, excluding other revenues | 720.6 | 713.9 | 716.4 | 6.7 | 1 | % | (2.5 | ) | — | % | ||||||||||||||||
Other revenues | 35.8 | 37.9 | 38.5 | (2.1 | ) | (6 | )% | (0.6 | ) | (2 | )% | |||||||||||||||
Net margin | 756.4 | 751.8 | 754.9 | 4.6 | 1 | % | (3.1 | ) | — | % | ||||||||||||||||
Operating costs | 410.6 | 422.0 | 398.8 | (11.4 | ) | (3 | )% | 23.2 | 6 | % | ||||||||||||||||
Depreciation and amortization | 130.1 | 132.2 | 131.0 | (2.1 | ) | (2 | )% | 1.2 | 1 | % | ||||||||||||||||
Operating income | $ | 215.7 | $ | 197.6 | $ | 225.1 | $ | 18.1 | 9 | % | $ | (27.5 | ) | (12 | )% | |||||||||||
Capital expenditures | $ | 280.3 | $ | 242.6 | $ | 215.6 | $ | 37.7 | 16 | % | $ | 27.0 | 13 | % | ||||||||||||
The following table sets forth our net margin, excluding other revenues, by type of customer, for the periods indicated:
Variances | Variances | |||||||||||||||||||||||||
Years Ended December 31 | 2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||||||||
Net Margin, Excluding Other Revenues | 2012 | 2011 | 2010 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
Gas sales | (Millions of dollars) | |||||||||||||||||||||||||
Residential | $ | 523.4 | $ | 510.5 | $ | 509.1 | $ | 12.9 | 3 | % | $ | 1.4 | — | % | ||||||||||||
Commercial | 101.6 | 105.5 | 108.9 | (3.9 | ) | (4 | )% | (3.4 | ) | (3 | )% | |||||||||||||||
Industrial | 2.2 | 2.4 | 2.2 | (0.2 | ) | (8 | )% | 0.2 | 9 | % | ||||||||||||||||
Wholesale/public authority | 4.6 | 4.6 | 4.7 | — | — | % | (0.1 | ) | (2 | )% | ||||||||||||||||
Net margin on gas sales | 631.8 | 623.0 | 624.9 | 8.8 | 1 | % | (1.9 | ) | — | % | ||||||||||||||||
Transportation margin | 88.8 | 90.9 | 91.5 | (2.1 | ) | (2 | )% | (0.6 | ) | (1 | )% | |||||||||||||||
Net margin, excluding other revenues | $ | 720.6 | $ | 713.9 | $ | 716.4 | $ | 6.7 | 1 | % | $ | (2.5 | ) | — | % | |||||||||||
2012 vs. 2011 - Net margin increased due primarily to the following:
• | an increase of $15.4 million from new rates in all three states; offset partially by |
• | a decrease of $8.5 million due to expiration of the Integrity Management Program (IMP) rider, which allowed Oklahoma Natural Gas to recover certain deferred pipeline-integrity costs in Oklahoma. This decrease is offset by lower regulatory amortization in depreciation and amortization expense; and |
• | a decrease of $2.2 million from lower transportation volumes due to weather-sensitive customers in Kansas and Oklahoma. |
Operating costs decreased due primarily to the following:
• | a decrease of $16.7 million in share-based compensation costs from common stock awarded in the prior year to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price during 2011; |
• | a decrease of $8.9 million in employee-related incentive and health benefit costs due to reduced short-term incentives and medical claims expenses; offset partially by |
• | an increase of $5.4 million in pension costs as a result of the annual change in our estimated discount rate; |
• | an increase of $4.8 million due primarily to expenses associated with outside services and pipeline maintenance; and |
• | an increase of $4.0 million in litigation expense. |
Depreciation and amortization expense decreased due primarily to a decrease of $8.5 million in regulatory amortization associated with the expiration of the IMP rider, offset partially by an increase of $6.1 million associated with additional capital expenditures.
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2011 vs. 2010 - Net margin decreased due primarily to the following:
• | a decrease of $5.9 million from lower sales in Kansas, due to lower consumption by residential and commercial customers as a result of warmer than normal weather in the first quarter; |
• | a decrease of $4.9 million due to expiration of the IMP rider. This decrease is offset partially by lower regulatory amortization in depreciation and amortization expense; offset partially by |
• | an increase of $3.3 million from new rates and rider recoveries in Texas; |
• | an increase of $2.1 million from customer growth, primarily in Texas; and |
• | an increase of $1.7 million from capital-recovery mechanisms in Kansas. |
Operating costs increased due primarily to the following:
• | an increase of $14.7 million in share-based compensation costs from common stock awarded to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price; |
• | an increase of $8.1 million in employee-related incentive and health benefit costs; and |
• | an increase of $3.2 million in pension costs as a result of the annual change in our estimated discount rate. |
Depreciation and amortization expense increased due primarily to an increase of $6.4 million associated with additional capital expenditures, specifically investments in automated meter reading in Oklahoma, offset partially by a decrease of $4.9 million in regulatory amortization associated with the expiration of the IMP rider.
Capital Expenditures - Our capital expenditures program includes expenditures for pipeline integrity, automated meter reading, extending service to new areas, modifications to customer-service lines, increasing system capabilities and replacements. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.
Capital expenditures increased for 2012, compared with 2011, primarily as a result of increased spending on pipeline replacements. Capital expenditures increased for 2011, compared with 2010, primarily as a result of increased spending on pipeline replacements, offset partially by decreased spending on automated meter reading.
Selected Operating Information - The following tables set forth certain selected information for our Distribution segment for the periods indicated:
Years Ended December 31, | |||||||||
Number of Customers | 2012 | 2011 | 2010 | ||||||
Residential | 1,932,484 | 1,921,017 | 1,912,205 | ||||||
Commercial | 153,032 | 153,227 | 153,650 | ||||||
Industrial | 1,220 | 1,248 | 1,271 | ||||||
Wholesale/public authority | 2,737 | 2,730 | 2,701 | ||||||
Transportation | 11,926 | 11,708 | 11,308 | ||||||
Total customers | 2,101,399 | 2,089,930 | 2,081,135 | ||||||
Years Ended December 31, | |||||||||
Volumes (MMcf) | 2012 | 2011 | 2010 | ||||||
Gas sales | |||||||||
Residential | 103,799 | 117,969 | 121,240 | ||||||
Commercial | 30,171 | 33,805 | 35,223 | ||||||
Industrial | 1,288 | 1,367 | 1,211 | ||||||
Wholesale/public authority | 6,135 | 3,287 | 12,060 | ||||||
Total volumes sold | 141,393 | 156,428 | 169,734 | ||||||
Transportation | 199,408 | 203,655 | 205,692 | ||||||
Total volumes delivered | 340,801 | 360,083 | 375,426 | ||||||
Residential and commercial volumes decreased for 2012, compared with 2011, due primarily to warmer temperatures in 2012; however, the impact on margins was mitigated largely by weather-normalization mechanisms. Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes increased for 2012, compared to 2011; however, the impact to net margin was minimal.
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Residential and commercial volumes decreased for 2011, compared with 2010, due primarily to warmer temperatures in the first quarter 2011.
Regulatory Initiatives - Oklahoma - In July 2012, a joint stipulation settling Oklahoma Natural Gas’ annual Performance Based Rate Change (PBRC) filing was approved by the OCC. The settlement granted a $9.5 million rate increase and modified Oklahoma Natural Gas’ PBRC tariff. The modified tariff narrows the range of allowed regulated return on equity (ROE) to a range of 10.0 percent to 11.0 percent from our previous range of 9.75 percent to 11.25 percent; increases the ROE reflected in any rate increase resulting from a revenue deficiency to 10.5 percent from 10.25 percent; and reduces the number of allowed pro forma adjustments that can be proposed by Oklahoma Natural Gas. Our next annual filing is required in March 2013.
In May 2011, the OCC approved a portfolio of conservation and energy-efficiency programs and authorized recovery of costs and performance incentives. The agreement allows Oklahoma Natural Gas to pursue key energy-efficiency programs and allows the company to earn up to $1.5 million annually, if program objectives are achieved. The Company made a filing to extend its Energy Efficiency program for another three years on January 22, 2013.
Kansas - In October 2012, Kansas Gas Service, the staff of the KCC and the Citizens’ Utility Ratepayer Board filed a joint motion to approve a stipulated settlement agreement granting a $28 million increase in base rates and an $18 million reduction in amounts currently recovered through surcharges, effectively increasing its annual revenues by a net amount of $10 million. The KCC approved this settlement in December 2012, and the new rates are effective January 2013.
In September 2012, the KCC denied Kansas Gas Service’s application to implement an infrastructure-replacement program that would allow Kansas Gas Service to accelerate the rate at which it is replacing cast-iron pipe. Costs incurred by Kansas Gas Service to replace cast-iron pipe are eligible for the Gas System Reliability Surcharge (GSRS). This surcharge is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return on incremental safety-related and government-mandated capital investments made between rate cases.
The KCC approved an application from Kansas Gas Service to increase the GSRS by an additional $2.9 million, effective January 2012.
Texas - Texas Gas Service has filed rate cases and requests for interim rate relief under the Gas Reliability Infrastructure Program (GRIP) and cost-of-service adjustments in various Texas jurisdictions to address investments in rate base and changes in expense. Annual rate increases totaling $10.1 million associated with these filings were approved in 2012.
In January 2012, the RRC approved a settlement between Texas Gas Service and the City of El Paso that allows for recovery of 2010-2013 pipeline-integrity expenditures and partial recovery of rate-case expenses. The settlement did not have a material impact on our results of operations.
General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for recognition and accordingly, a write-off of regulatory assets and stranded costs may be required. There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during 2012, 2011 or 2010.
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Energy Services
Selected Financial Results - The following table sets forth certain selected financial results for our Energy Services segment for the periods indicated:
Variances | Variances | |||||||||||||||||||||||||
Years Ended December 31, | 2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||||||||
Financial Results | 2012 | 2011 | 2010 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
(Millions of dollars) | ||||||||||||||||||||||||||
Revenues | $ | 1,526.6 | $ | 2,777.2 | $ | 3,301.2 | $ | (1,250.6 | ) | (45 | )% | $ | (524.0 | ) | (16 | )% | ||||||||||
Cost of sales and fuel | 1,575.9 | 2,728.5 | 3,141.5 | (1,152.6 | ) | (42 | )% | (413.0 | ) | (13 | )% | |||||||||||||||
Net margin | (49.3 | ) | 48.7 | 159.7 | (98.0 | ) | * | (111.0 | ) | (70 | )% | |||||||||||||||
Operating costs | 18.0 | 24.5 | 28.4 | (6.5 | ) | (27 | )% | (3.9 | ) | (14 | )% | |||||||||||||||
Depreciation and amortization | 0.3 | 0.4 | 0.6 | (0.1 | ) | (25 | )% | (0.2 | ) | (33 | )% | |||||||||||||||
Goodwill impairment | 10.3 | — | — | 10.3 | 100 | % | — | — | % | |||||||||||||||||
Operating income (loss) | $ | (77.9 | ) | $ | 23.8 | $ | 130.7 | $ | (101.7 | ) | * | $ | (106.9 | ) | (82 | )% | ||||||||||
*Percentage change is greater than 100 percent.
The following table sets forth our margins by activity for the periods indicated:
Variances | Variances | |||||||||||||||||||||||||
Years Ended December 31, | 2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||||||||
2012 | 2011 | 2010 | Increase (Decrease) | Increase (Decrease) | ||||||||||||||||||||||
(Millions of dollars) | ||||||||||||||||||||||||||
Marketing, storage and transportation revenues, gross | $ | 105.6 | $ | 208.0 | $ | 342.9 | $ | (102.4 | ) | (49 | )% | $ | (134.9 | ) | (39 | )% | ||||||||||
Storage and transportation costs | 157.3 | 161.2 | 189.4 | (3.9 | ) | (2 | )% | (28.2 | ) | (15 | )% | |||||||||||||||
Marketing, storage and transportation, net | (51.7 | ) | 46.8 | 153.5 | (98.5 | ) | * | (106.7 | ) | (70 | )% | |||||||||||||||
Financial trading, net | 2.4 | 1.9 | 6.2 | 0.5 | 26 | % | (4.3 | ) | (69 | )% | ||||||||||||||||
Net margin | $ | (49.3 | ) | $ | 48.7 | $ | 159.7 | $ | (98.0 | ) | * | $ | (111.0 | ) | (70 | )% | ||||||||||
*Percentage change is greater than 100 percent.
Marketing, storage and transportation revenues, gross, primarily include marketing, purchases and sales, premium services and the impact of cash flow and fair value hedges and other derivative instruments used to manage our risk associated with these activities. Storage and transportation costs primarily include the cost of leasing capacity, storage injection and withdrawal fees, fuel charges and gathering fees. Risk management and operational decisions have an impact on the net result of our marketing, premium-services and storage activities. These decisions can benefit margins in one line of business while decreasing margins in another. We evaluate our strategies on an ongoing basis to optimize the value of our contracted assets and to minimize the financial impact of market conditions on the services we provide. While the financial impact on our overall business activities could be minimal, the impact to varying lines of business could be significant.
The decrease in our storage and transportation costs in both 2012 and 2011 primarily reflects reduced transportation capacity, offset partially by an increase in storage demand fees.
For additional information on transportation and storage capacity, refer to “Selected Operating Information” below.
Financial trading, net, includes activities that are executed generally using financially settled derivatives. These activities are normally short term in nature, with a focus on capturing short-term price volatility. Revenues in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are reported on a net basis.
Revenues and cost of sales and fuel have decreased in both 2012 and 2011 due primarily to lower natural gas prices.
2012 vs. 2011 - The factors discussed in Energy Services’ “Narrative Description of the Business” included in Item I, Business, of this Annual Report have led to a significant decrease in net margin.
In 2012, we realized $44.6 million in premium-services margins, and our storage and marketing margins consisted of $40.0 million from realized seasonal price differentials and marketing optimization activities and $89.9 million of storage demand
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costs. Our 2012 results were lower than 2011 when we realized $53.1 million in premium-services margins and our storage and marketing margins consisted of $96.0 million from realized seasonal price differentials and marketing optimization activities, and $87.7 million of storage demand costs. In addition, we recognized a loss on the change in fair value of our nonqualifiying economic storage hedges of $1.0 million in 2012 compared with a gain of $8.5 million in 2011. Our premium services were impacted negatively by lower natural gas prices and decreased natural gas price volatility. The impact of our hedge strategies and the inability to hedge seasonal price differentials at levels that were available to us in the prior year significantly reduced our storage margins. We also experienced reduced opportunities to optimize our storage assets, which negatively impacted our marketing margins.
We realized a loss in our transportation margins of $42.4 million in 2012 compared with a loss of $18.8 million in 2011, due primarily to a $29.5 million decrease in transportation hedges. Our transportation business continues to be impacted by narrow price location differentials and the inability to hedge at levels that were available to us in prior years. As a result of significant increases in the supply of natural gas, primarily from shale gas production across North America and new pipeline infrastructure projects, location and seasonal price differentials narrowed significantly beginning in 2010 and continuing through 2012. This market change resulted in our transportation contracts being unprofitable impacting our ability to recover our fixed costs.
Operating costs decreased due primarily to lower employee-related expenses, which includes the impact of fewer employees.
We also recognized an expense of $10.3 million related to the impairment of our goodwill in the first quarter 2012. Given the significant decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment in the first quarter 2012 that reduced our goodwill balance to zero.
2011 vs. 2010 - The factors discussed in Energy Services’ “Narrative Description of the Business” included in Item I, Business, of this Annual Report have led to a significant decrease in net margin, including:
• | a decrease of $65.3 million in transportation margins, net of hedging, due primarily to narrower location price differentials and lower hedge settlements in 2011; |
• | a decrease of $34.3 million in storage and marketing margins, net of hedging activities, due primarily to the following: |
– | lower realized seasonal storage price differentials; offset partially by |
– | favorable marketing activity and unrealized fair value changes on nonqualifying economic storage hedges; |
• | a decrease of $7.3 million in premium-services margins, associated primarily with the reduction in the value of the fees collected for these services as a result of low commodity prices and reduced natural gas price volatility in the first quarter 2011 compared with the first quarter 2010; and |
• | a decrease of $4.3 million in financial trading margins, as low natural gas prices and reduced natural gas price volatility limited our financial trading opportunities. |
Additionally, our 2011 net margin includes $91.1 million in adjustments to natural gas inventory reflecting the lower of cost or market value. Because of the adjustments to our inventory value, we reclassified $91.1 million of deferred gains on associated cash flow hedges into earnings.
Operating costs decreased due primarily to a decrease in ad valorem taxes.
Selected Operating Information - The following table sets forth certain selected operating information for our Energy Services segment for the periods indicated:
Years Ended December 31, | ||||||||||||
Operating Information | 2012 | 2011 | 2010 | |||||||||
Natural gas marketed (Bcf) | 709 | 845 | 919 | |||||||||
Natural gas gross margin ($/Mcf) | $ | (0.07 | ) | $ | 0.06 | $ | 0.18 | |||||
Physically settled volumes (Bcf) | 1,433 | 1,724 | 1,874 | |||||||||
Natural gas volumes marketed and physically settled volumes decreased in 2012 compared with 2011 due primarily to decreased marketing activities, lower transported volumes and reduced transportation capacity. The decrease in 2011 compared with 2010 was due primarily to lower volumes transported and reduced transportation capacity. Transportation capacity in certain markets was not utilized due to the economics of the location price differentials as a result of increased supply of natural gas, primarily from shale production, and increased pipeline capacity as a result of new pipeline construction.
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At December 31, 2012, our natural gas transportation capacity was 1.0 Bcf/d, of which 1.0 Bcf/d was contracted under term natural gas transportation contracts, compared with 1.2 Bcf/d of total capacity and 1.1 Bcf/d of long-term capacity at December 31, 2011. Approximately 311.1 MMcf/d, or 32 percent, of our transportation capacity expires by the end of 2013, and an additional 390.4 MMcf/d, or 41 percent, of our transportation capacity expires by the end of 2015.
Our natural gas in storage at December 31, 2012, was 55.5 Bcf, compared with 70.5 Bcf at December 31, 2011. At December 31, 2012, our total natural gas storage capacity under lease was 71.5 Bcf, compared with 75.6 Bcf at December 31, 2011. At December 31, 2012, our natural gas storage capacity under lease had a maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.3 Bcf/d. Approximately 22.3 Bcf, or 31 percent, of our storage capacity expires by the end of 2013, and an additional 40.5 Bcf, or 57 percent, of our storage capacity expires by the end of 2015.
Reducing storage and transportation capacity continues to be a focus as we reduce fixed costs and align our capacity with the needs of our premium-services customers. It is possible that we may recognize charges to our earnings in the future as a result of these actions.
CONTINGENCIES
Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, and we are unable to estimate reasonably possible losses, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in this Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
General - ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, debt issuances and/or the issuance of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow. Capital expenditures are funded by short- and long-term debt, issuances of equity and operating cash flow. We expect to continue to use these sources for our liquidity and capital resource needs. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners.
ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings. We anticipate that our cash flow generated from operations, existing capital resources, including proceeds from the issuance of our $700 million 4.25-percent senior notes issued in January 2012, and distributions from ONEOK Partners will enable us to maintain our current and planned level of operations and provide us flexibility should we elect to execute on any portion of the $300 million remainder of our three-year, $750-million stock repurchase program. ONEOK Partners anticipates that its cash flow generated from operations, proceeds from its March 2012 equity offering, September 2012 debt offering, existing capital resources and ability to obtain financing will enable it to maintain its current and planned level of operations. Additionally, ONEOK Partners expects to fund its future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.
Capitalization Structure - The following table sets forth ONEOK’s capital structure, excluding the debt of ONEOK Partners, for the periods indicated:
December 31, 2012 | December 31, 2011 | |||
Long-term debt | 45% | 31% | ||
ONEOK shareholders’ equity | 55% | 69% | ||
Debt (including notes payable) | 54% | 45% | ||
ONEOK shareholders’ equity | 46% | 55% | ||
As the sole general partner of ONEOK Partners, ONEOK is responsible for directing the activities of ONEOK Partners, but ONEOK is not liable for, nor does it guarantee, any of ONEOK Partners’ liabilities. Likewise, ONEOK Partners is not liable for, nor does it guarantee, any of ONEOK’s liabilities. Significant legal and financial separations exist between ONEOK and
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ONEOK Partners. Additionally, for purposes of determining compliance with financial covenants in the ONEOK Credit Agreement, which are described below, the debt of ONEOK Partners is excluded.
The following table sets forth our consolidated capitalization structure for the periods indicated:
December 31, 2012 | December 31, 2011 | |||
Long-term debt | 61% | 56% | ||
Total equity | 39% | 44% | ||
Debt (including notes payable) | 63% | 60% | ||
Total equity | 37% | 40% | ||
Stock Repurchase - In 2012, we completed an accelerated share repurchase agreement in which we repurchased approximately 3.4 million shares of our common stock for $150 million.
Cash Management - ONEOK and ONEOK Partners each use similar centralized cash management programs that concentrate the cash assets of their operating subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Both centralized cash management programs provide that funds in excess of the daily needs of the operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the respective consolidated groups. ONEOK Partners’ operating subsidiaries participate in these programs to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under these cash management programs, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, ONEOK and ONEOK Partners provide cash to their respective subsidiaries or the subsidiaries provide cash to them.
Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners and our $1.2 billion commercial paper program. ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities, the issuance of commercial paper and distributions received from unconsolidated affiliates. To the extent commercial paper is unavailable, ONEOK’s and ONEOK Partners’ respective revolving credit agreements may be utilized.
At December 31, 2012, the weighted-average interest rate on ONEOK’s short-term debt outstanding was 0.46 percent. The weighted-average interest rates for the year ended December 31, 2012, on ONEOK’s and ONEOK Partners’ short-term borrowings were 0.47 percent and 0.40 percent, respectively. Based on the forward LIBOR curve, we expect the interest rates on ONEOK’s and ONEOK Partners’ short-term borrowings to increase in 2013, compared with interest rates on amounts outstanding at December 31, 2012.
ONEOK Credit Agreement - The ONEOK Credit Agreement, which is scheduled to expire in April 2016, contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 67.5 percent at the end of any calendar quarter, limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets, a requirement that ONEOK maintain the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships.
The ONEOK Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends. The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners. Upon breach of certain covenants by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become due and payable immediately. At December 31, 2012, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 52.2 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.
Under the terms of the ONEOK Credit Agreement, ONEOK may request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Credit Agreement is available for general corporate purposes, including repayment of ONEOK’s commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Credit Agreement.
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The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.8 billion. At December 31, 2012, ONEOK had $817.2 million of commercial paper outstanding, $1.9 million in letters of credit issued under the ONEOK Credit Agreement and approximately $46.5 million of cash and cash equivalents. ONEOK had approximately $380.9 million of credit available at December 31, 2012, under the ONEOK Credit Agreement. As of December 31, 2012, ONEOK could have issued $2.3 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.
The ONEOK Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Borrowings, if any, will accrue at LIBOR plus 150 basis points, and the annual facility fee is 25 basis points based on our current credit rating.
ONEOK Partners Credit Agreement - The ONEOK Partners Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the quarter of the acquisition and the two following quarters. Upon breach of certain covenants by ONEOK Partners in the ONEOK Partners Credit Agreement, amounts outstanding under the ONEOK Partners Credit Agreement, if any, may become due and payable immediately. At December 31, 2012, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.0 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.
The ONEOK Partners Credit Agreement includes a $100-million sublimit for the issuance of standby letters of credit and also features an option to request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Partners Credit Agreement is available for general partnership purposes, including repayment of ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement.
The ONEOK Partners Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in ONEOK Partners’ credit rating. Borrowings, if any, will accrue at LIBOR plus 130 basis points, and the annual facility fee is 20 basis points based on ONEOK Partners’ current credit rating. The ONEOK Partners Credit Agreement is guaranteed fully and unconditionally by ONEOK Partners’ wholly owned subsidiary, ONEOK Partners Intermediate Limited Partnership. Borrowings under the ONEOK Partners Credit Agreement are nonrecourse to ONEOK.
The total amount of short-term borrowings authorized by the Board of Directors of ONEOK Partners GP, the general partner of ONEOK Partners, is $2.5 billion. At December 31, 2012, ONEOK Partners had no commercial paper outstanding, no letters of credit issued, no borrowings outstanding under the ONEOK Partners Credit Agreement, approximately $537.0 million of cash and $1.2 billion of credit available under the ONEOK Partners Credit Agreement. As of December 31, 2012, ONEOK Partners could have issued $3.2 billion of short- and long-term debt to meet its liquidity needs under the most restrictive provisions contained in its various borrowing agreements.
Effective August 1, 2012, ONEOK Partners extended the maturity of its ONEOK Partners Credit Agreement to August 1, 2017, from August 1, 2016, pursuant to an extension agreement between ONEOK Partners and its lenders.
Recent events in the European economy could impact European banks. Various European-based banks participate in the ONEOK Credit Agreement and the ONEOK Partners Credit Agreement, representing an aggregate of $340 million and $342 million in committed capacity, respectively. These banks are of significant scale and international diversification, which we believe minimizes the risk of these banks being unable to fulfill their commitments to us or ONEOK Partners under our respective credit agreements. Should any of these banks be unable to fund any future borrowings under the credit agreements, we believe other funding sources likely would be available to replaced the European banks’ commitments.
Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, ONEOK expects to fund its longer-term cash requirements by issuing equity or long-term notes. ONEOK Partners expects to fund its longer-term cash requirements by issuing common units or long-term notes. Other options to obtain financing include, but are not limited to, issuance of convertible debt securities, asset securitization and the sale and leaseback of facilities.
ONEOK and ONEOK Partners are subject to changes in the debt and equity markets, and there is no assurance they will be able or willing to access the public or private markets in the future. ONEOK and ONEOK Partners may choose to meet their
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cash requirements by utilizing some combination of cash flows from operations, borrowing under existing commercial paper or credit facilities, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, or pursuing other debt or equity financing alternatives. Some of these alternatives could involve higher costs or negatively affect their respective credit ratings, among other factors. Based on ONEOK’s and ONEOK Partners’ investment-grade credit ratings, general financial condition and market expectations regarding their future earnings and projected cash flows, ONEOK and ONEOK Partners believe that they will be able to meet their respective cash requirements and maintain their investment-grade credit ratings.
ONEOK Debt Issuance - In January 2012, we completed an underwritten public offering of $700 million of 4.25-percent senior notes due 2022. The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million were used to repay amounts outstanding under our commercial paper program and for general corporate purposes. We will pay interest on the senior notes due 2022 on February 1 and August 1 of each year.
ONEOK Debt Covenants - The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.
ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest. ONEOK may redeem its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three month before the maturity date. Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.
ONEOK Partners Equity Issuances - ONEOK Partners entered into the EDA for the offer and sale from time to time of ONEOK Partners’ common units up to an aggregate amount of $300 million. The EDA allows ONEOK Partners to offer and sell its common units representing limited partner interests at prices ONEOK Partners deems appropriate through a sales agent. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between ONEOK Partners and the sales agent. ONEOK Partners is under no obligation to offer common units under the EDA. ONEOK Partners intends to use the net proceeds from sales under the program for general partnership purposes.
In March 2012, ONEOK Partners completed an underwritten public offering of 8.0 million common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million. ONEOK Partners also sold 8.0 million common units to us in a private placement, generating net proceeds of approximately $460 million. In conjunction with the issuances, ONEOK Partners GP contributed approximately $19 million in order to maintain its 2-percent general partner interest in ONEOK Partners. ONEOK Partners used the net proceeds from the issuances to repay $295 million of borrowings under its commercial paper program, to repay amounts on the maturity of ONEOK Partners’ $350 million, 5.9-percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures. As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent from 42.8 percent.
ONEOK Partners’ Debt Issuance and Maturities - In September 2012, ONEOK Partners completed an underwritten public offering of $1.3 billion of senior notes, consisting of $400 million, 2.0-percent senior notes due 2017 and $900 million, 3.375-percent senior notes due 2022. A portion of the net proceeds from the offering of approximately $1.3 billion was used to repay amounts outstanding under its commercial paper program, and the balance will be used for general partnership purposes, including capital expenditures.
In January 2011, ONEOK Partners completed an underwritten public offering of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering were approximately $1.3 billion and were used to repay amounts outstanding under its commercial paper program, to repay its $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.
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ONEOK Partners’ Debt Covenants - ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on ONEOK Partners’ property or assets and to sell and lease back ONEOK Partners’ property. The indentures governing ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in full.
ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes on the same terms as its other senior notes. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries. ONEOK Partners’ senior notes are nonrecourse to ONEOK.
Interest-rate Swaps - ONEOK entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. ONEOK had interest-rate swaps with notional values totaling $500 million at December 31, 2011. In January 2012, ONEOK entered into additional interest-rate swaps with notional amounts totaling $200 million. Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income (loss) that will be amortized to interest expense
over the term of the related debt.
ONEOK Partners entered into forward-starting interest-rate swaps to hedge the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At December 31, 2011, ONEOK Partners had interest-rate swaps with notional values totaling $750 million. During 2012, ONEOK Partners entered into additional interest-rate swaps with notional amounts totaling $650 million. Upon ONEOK Partners’ debt issuance in September 2012, ONEOK Partners settled $1.0 billion of its interest-rate swaps and realized a loss of $124.9 million in accumulated other comprehensive income (loss) that will be amortized to interest expense over the term of the related debt. At December 31, 2012, ONEOK Partners’ remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates greater than 12 months.
Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $1,866.2 million, $1,336.1 million and $582.7 million for 2012, 2011 and 2010, respectively. Of these amounts, ONEOK Partners’ capital expenditures were $1,560.5 million, $1,063.4 million and $352.7 million for 2012, 2011 and 2010, respectively. Capital expenditures for 2012 increased, compared with 2011, due primarily to the growth projects in ONEOK Partners’ natural gas liquids business.
The following table sets forth our 2013 projected capital expenditures, excluding AFUDC:
2013 Projected Capital Expenditures | |||
(Millions of dollars) | |||
ONEOK Partners | $ | 2,640 | |
Natural Gas Distribution | 286 | ||
Other | 30 | ||
Total projected capital expenditures | $ | 2,956 | |
Unconsolidated Affiliates - The Overland Pass Pipeline Company limited liability company agreement provides that distributions to Overland Pass Pipeline Company’s members are to be made on a pro-rata basis according to each member’s ownership interest. The Overland Pass Pipeline Company Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, cash distributions from Overland Pass Pipeline Company requires the
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unanimous approval of the Overland Pass Pipeline Management Committee. Cash distributions are equal to 100 percent of available cash as defined in the limited liability company agreement.
The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro-rata basis according to each partner’s percentage interest. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100 percent of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon EBITDA, less interest expense and maintenance capital expenditures. Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit agreement. The Northern Border Pipeline Management Committee has adopted a cash distribution policy related to financial ratio targets and capital contributions. The cash distribution policy defines minimum equity-to-total-capitalization ratios to be used by the Northern Border Pipeline Management Committee to establish the timing and amount of required capital contributions. In addition, any shortfall due to the inability to refinance maturing debt will be funded by capital contributions.
Credit Ratings - ONEOK’s and ONEOK Partners’ credit ratings as of December 31, 2012, are shown in the table below:
ONEOK | ONEOK Partners | ||||||
Rating Agency | Rating | Outlook | Rating | Outlook | |||
Moody’s | Baa2 | Stable | Baa2 | Stable | |||
S&P | BBB | Stable | BBB | Stable | |||
ONEOK’s and ONEOK Partners’ commercial paper programs are each rated Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which currently are investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners currently do not anticipate their respective credit ratings to be downgraded; however, if ONEOK’s or ONEOK Partners’ credit ratings were downgraded, the cost to borrow funds under their respective commercial paper programs and credit agreements would increase, and ONEOK or ONEOK Partners potentially could lose access to the commercial paper market. If ONEOK and ONEOK Partners are unable to borrow funds under their respective commercial paper programs and there has not been a material adverse change in their businesses, ONEOK and ONEOK Partners would continue to have access to the ONEOK Credit Agreement and the ONEOK Partners Credit Agreement, respectively. An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement.
Our Energy Services segment relies upon the investment-grade rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At December 31, 2012, ONEOK could have been required to fund approximately $2.6 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit rating below investment grade also may impact significantly other business segments.
In the normal course of business, ONEOK’s and ONEOK Partners’ counterparties provide secured and unsecured credit. In the event of a downgrade in ONEOK’s or ONEOK Partners’ credit ratings or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties.
Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices will impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 74 under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.
Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note M of the Notes to Consolidated Financial Statements in this Annual Report.
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During 2012, we made contributions of $91.9 million and $10.7 million to our defined benefit pension plans and postretirement benefit plans, respectively. In 2013, we expect to contribute $4.8 million and $11.8 million to our defined benefit pension plans and postretirement benefit plans, respectively.
CASH FLOW ANALYSIS
We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, allowance for equity funds used during construction, gain or loss on sale of assets, equity earnings from investments, distributions received from unconsolidated affiliates, deferred income taxes, share-based compensation expense, other amounts, and changes in our assets and liabilities not classified as investing or financing activities.
The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Millions of dollars) | ||||||||||||
Total cash provided by (used in): | ||||||||||||
Operating activities | $ | 990.9 | $ | 1,360.0 | $ | 834.0 | ||||||
Investing activities | (1,814.2 | ) | (1,371.6 | ) | (134.3 | ) | ||||||
Financing activities | 1,332.1 | 55.4 | (698.1 | ) | ||||||||
Change in cash and cash equivalents | 508.8 | 43.8 | 1.6 | |||||||||
Change in cash and cash equivalents included in discontinued operations | 8.9 | (8.2 | ) | (2.2 | ) | |||||||
Change in cash and cash equivalents from continuing operations | 517.7 | 35.6 | (0.6 | ) | ||||||||
Cash and cash equivalents at beginning of period | 66.0 | 30.4 | 30.9 | |||||||||
Cash and cash equivalents at end of period | $ | 583.6 | $ | 66.0 | $ | 30.3 | ||||||
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows.
2012 vs. 2011 - Cash flows from operating activities, before changes in operating assets and liabilities, were approximately $1,347.2 million for 2012 compared with $1,397.7 million for 2011. The decrease was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information on pages 45-46.
The changes in operating assets and liabilities decreased operating cash flows $356.3 million for 2012, compared with a decrease of $37.7 million for the same period in 2011. The change was due primarily to the settlement of interest-rate swaps associated with ONEOK’s $700 million debt issuance in January 2012 and ONEOK Partners’ $1.3 billion debt issuance in September 2012; and the change in natural gas and natural gas liquids in storage. The change in natural gas and NGLs in storage results from changes in storage levels and the impact of commodity prices on the purchase cost of inventory, both of which vary from period to period. The change in operating assets and liabilities was also impacted by the collection and payment of trade receivables and payables, resulting from the timing of cash collections from customers and paid to vendors and suppliers, both of which vary from period to period.
2011 vs. 2010 - Cash flows from operating activities, before changes in operating assets and liabilities, were $1,397.7 million for 2011, compared with $994.9 million for 2010. The increase was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information on page 46.
The changes in operating assets and liabilities decreased operating cash flows $37.7 million for 2011, compared with a decrease of $160.9 million for 2010. The change was due primarily to the collection and payment of trade receivables and payables, resulting from the timing of invoices collected from customers and paid to vendors and suppliers, which vary from period to period; and a decrease in volumes of NGLs in storage in our ONEOK Partners segment during 2011, compared with an increase in volumes in storage in our ONEOK Partners segment during 2010.
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Investing Cash Flows - Cash used in investing activities increased for 2012, compared with 2011, due primarily to ONEOK Partners’ growth projects in its natural gas liquids business, offset partially by proceeds from the sale of ONEOK Energy Marketing Company.
Cash used in investing activities increased for 2011, compared with 2010, due primarily to ONEOK Partners’ growth projects in its natural gas gathering and processing and natural gas liquids businesses and the $423.7 million in proceeds ONEOK Partners received from the Overland Pass Pipeline transaction in September 2010.
Financing Cash Flows - Cash provided by financing activities increased for 2012 compared with 2011. The change is a result of ONEOK’s 2012 debt issuance and ONEOK Partners’ 2012 common units issuance. The net cash flows provided by these financing activities were offset partially by the repayment of a scheduled maturity of ONEOK Partners long-term debt, ONEOK’s $150 million share repurchase, increased distributions to noncontrolling interests and increased dividends paid. Financing cash flows also reflect net proceeds from ONEOK Partners’ debt issuances of $1.3 billion in both 2012 and 2011.
Cash provided by financing activities increased for 2011 compared with 2010. The change is a result of ONEOK Partners’ January 2011 debt issuance, from which a portion of the proceeds were used to repay ONEOK Partners’ short-term borrowings and the March 2011 maturity of a portion of ONEOK Partners’ long-term debt. The net cash flows provided by these financing activities were offset partially by the repayment of a scheduled maturity of ONEOK’s long-term debt, ONEOK’s $300 million share repurchase in May 2011, increased distributions to noncontrolling interests and increased dividends.
REGULATORY AND ENVIRONMENTAL MATTERS
Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and regulations affecting many aspects of our present and future operations. Regulated activities include but are not limited to those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetland preservation, hazardous materials transportation and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In May 2010, the EPA finalized the “Tailoring Rule” that regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011, and at current emission threshold levels has not had a material impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.
In 2010, the EPA issued a rule on air-quality standards titled, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, which initially included a compliance date in 2013. Subsequent industry appeals and settlements with the EPA have extended timelines associated with the final RICE NESHAP rule. Generally, while the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.
Additional information about our environmental matters is included in “Environmental and Safety Matters” of Item 1, Business and Note Q of the Notes to Consolidated Financial Statements in this Annual Report. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition and results of operations. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or
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results of operations, and our expenditures related to environmental matters did not have a material impact on earnings or cash flows during 2012, 2011 and 2010.
Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act. The CFTC has issued final regulations for many provisions of the Dodd-Frank Act that have varying effective dates for compliance, but others remain outstanding. Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the capital requirements and costs of hedging may increase as a result of the regulations. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material. These requirements could affect adversely market liquidity and pricing of derivative contracts, making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Natural Gas Distribution segment. See discussion of our Natural Gas Distribution segment’s regulatory initiatives beginning on page 56.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report.
ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
The following is a summary of our most critical accounting policies, which are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our estimates and critical accounting policies with the Audit Committee of our Board of Directors.
Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed.
While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. Inputs into our fair value estimates include commodity exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money-market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.
In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner and over a reasonable period of time using current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitoring the credit default swap markets. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.
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The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements.
Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
• | Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities; |
• | Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and |
• | Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data. |
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. Transfers in and out of Level 3 typically result from derivatives for which fair value is determined based on multiple inputs. If prices change for a particular input from the previous measurement date to the current measurement date, the impact could result in the derivative being moved between Level 2 and Level 3, depending upon management’s judgment of the significance of the price change of that particular input to the total fair value of the derivative.
For more information on our fair value measurements, fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note C of the Notes to Consolidated Financial Statements in this Annual Report.
Derivatives, Accounting for Financially Settled Transactions and Risk Management Activities - We engage in wholesale energy marketing, trading and risk-management activities. We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery.
Market value changes result in a change in the fair value of our derivative instruments. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the nature of the risk being hedged and how effective the hedging instrument is. When possible, we implement effective hedging strategies using derivative instruments that qualify as hedges for accounting purposes. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then we account for changes in fair value of the derivative in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in any given period.
To reduce our market risk exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forwards, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate and fuel requirements. Interest-rate swaps are also used to manage interest-rate risk. Under certain conditions, we designate these derivative instruments as a hedge against our exposure to changes in fair values or cash flow. For hedges of exposure to changes in cash flow, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss) and is subsequently recorded to earnings when the forecasted transaction affects earnings. Any ineffectiveness of designated hedges is reported in earnings during the period the ineffectiveness occurs. However, if a derivative instrument is ineligible for hedge accounting or if the cash flow hedge is not properly designated, changes in fair value of the derivative instrument would be recorded currently in earnings. Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings.
For hedges against our exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness test on our hedging relationships to determine whether they are highly effective on a retrospective and prospective basis.
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Upon election, many of our purchase and sale agreements that result in physical delivery and that otherwise would be required to follow the accounting for derivative instruments qualify as normal purchases and normal sales exceptions and are therefore exempt from fair value accounting treatment.
For more information on our derivatives and risk management activities, fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note D of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion.
Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually as of July 1. As a result of the decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment of our Energy Services segment’s goodwill balance as of March 31, 2012. As a result of that assessment, goodwill with a carrying amount of $10.3 million was written down to its implied fair value of zero, with a resulting impairment charge of $10.3 million recorded in 2012 earnings. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services.
Our goodwill impairment analysis performed as of July 1, 2012, did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets. There were no impairment charges resulting from our 2011 or 2010 annual impairment tests.
As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill. In the first step, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds the implied fair value of the goodwill, we will record an impairment charge.
To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply multiples to forecasted cash flows. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows over a period of years.
As part of our indefinite-lived intangible asset impairment test, we compare the estimated fair value of our indefinite-lived intangible asset with its book value. The fair value of our indefinite-lived intangible asset is estimated using the market approach. Under the market approach, we apply multiples to forecasted cash flows of the assets associated with our indefinite-lived intangible asset. The multiples used are consistent with historical asset transactions. We determined that there were no impairments to our indefinite-lived intangible asset in 2012, 2011 or 2010.
We assess our long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no asset impairments in 2012, 2011 or 2010.
For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry our equity method investments to determine whether current events or circumstances warrant adjustments to our carrying value. We determined that there were no impairments to our investments in unconsolidated affiliates in 2012, 2011 or 2010.
Low natural gas prices and the relatively higher crude oil and NGL prices compared with natural gas on a heating-value basis have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with
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dry natural gas production, such as the Powder River Basin. The reduced development activities and natural production declines in the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects. Bighorn Gas Gathering, in which ONEOK Partners owns a 49-percent equity interest, has operations in the Powder River Basin. Due to declines in natural gas volumes gathered on Bighorn Gas Gathering’s system, ONEOK Partners tested its investment for impairment. The carrying amount of ONEOK Partners’ investment as of December 31, 2012, was $90.4 million, which includes $53.4 million in equity method goodwill. ONEOK Partners estimated the fair value of its investment in Bighorn Gas Gathering using an income approach, which discounted the cash flows of ONEOK Partners investment’s underlying assets with a discount rate reflective of its cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures. The fair value exceeded the carrying value; therefore, no impairment was recorded.
A continued decline in natural gas volumes in the Powder River Basin may reduce ONEOK Partners’ ability to recover the carrying value of its assets and equity investments in this area and could result in noncash charges to earnings. A 10-percent decline in the fair value of ONEOK Partners’ investment in Bighorn Gas Gathering would result in a noncash impairment charge. For ONEOK Partners’ other equity method investments with operations in the Powder River Basin with carrying values of approximately $200 million, which includes approximately $130 million in equity method goodwill, ONEOK Partners did not identify current events or circumstances that warranted an impairment analysis or an adjustment to its carrying values. ONEOK Partners is not able to reasonably estimate a range of potential future charges, as many of the assumptions that would be used in a fair value model are dependent upon events such as commodity prices, producers’ drilling and production activity and effects of government regulations and policies.
Our impairment tests require the use of assumptions and estimates such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.
See Notes E and F of the Notes to Consolidated Financial Statements for our goodwill and long-lived assets disclosures.
Pension and Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the costs and liabilities we recognize. See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional information.
During 2012, we recorded net periodic benefit costs of $48.6 million related to our defined benefit pension plans and $16.0 million related to postretirement benefits. We estimate that in 2013, we will record net periodic benefit costs of $63.3 million related to our defined benefit pension plans and $10.2 million related to postretirement benefits.
The following table sets forth the weighted-average assumptions used to determine our estimated 2013 net periodic benefit cost related to our defined benefit pension plans, and sensitivity to changes with respect to these assumptions:
Rate Used | Cost Sensitivity (a) | Obligation Sensitivity (b) | ||||||||
(Millions of dollars) | ||||||||||
Discount rate | 4.25% | $ | 4.3 | $ | 42.5 | |||||
Expected long-term return on plan assets | 8.25% | $ | 2.5 | $ | — | |||||
(a) Approximate impact a quarter percentage point decrease in the assumed rate would have on net periodic pension costs. | ||||||||||
(b) Approximate impact a quarter percentage point decrease in the assumed rate would have on defined benefit pension obligation. | ||||||||||
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In determining our 2013 estimated net periodic benefit costs for our postretirement benefits, we assumed a discount rate of 4.0 percent and an expected long-term return on plan assets of 8.25 percent. A quarter percentage point decrease in either of the assumed rates would not have a significant impact on our postretirement benefit plan costs or obligation. Assumed health care cost-trend rates have a significant effect on the amounts reported for our postretirement benefit plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
One Percentage Point Increase | One Percentage Point Decrease | |||||||
(Millions of dollars) | ||||||||
Effect on total of service and interest cost | $ | 1.4 | $ | (1.2 | ) | |||
Effect on postretirement benefit obligation | $ | 17.5 | $ | (16.1 | ) | |||
During 2012, we made contributions of $91.9 million and $10.7 million to our defined benefit pension plans and postretirement benefit plans, respectively. In 2012, all contributions to our defined benefit pension plans were attributable to the 2013 plan year. In 2013, we expect to contribute $4.8 million and $11.8 million to our defined benefit pension plans and postretirement benefit plans, respectively.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect on earnings or cash flows during 2012, 2011 and 2010. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note Q of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, operating leases and other long-term obligations as of December 31, 2012. For additional discussion of the debt and operating lease agreements, see Notes H and Q, respectively, of the Notes to the Consolidated Financial Statements in this Annual Report.
Payments Due by Period | |||||||||||||||||||||||||||
Contractual Obligations | Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | ||||||||||||||||||||
ONEOK | (Millions of dollars) | ||||||||||||||||||||||||||
Commercial paper | $ | 817.2 | $ | 817.2 | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
Long-term debt | 1,689.2 | 3.2 | 3.0 | 403.0 | 3.0 | 3.0 | 1,274.0 | ||||||||||||||||||||
Interest payments on debt | 1,036.4 | 87.1 | 86.9 | 74.6 | 65.8 | 65.6 | 656.4 | ||||||||||||||||||||
Operating leases | 3.0 | 1.2 | 1.0 | 0.6 | 0.2 | — | — | ||||||||||||||||||||
Firm transportation and storage contracts | 334.9 | 130.3 | 99.1 | 53.5 | 27.6 | 15.0 | 9.4 | ||||||||||||||||||||
Financial and physical derivatives | 495.1 | 467.6 | 27.5 | — | — | — | — | ||||||||||||||||||||
Employee benefit plans | 16.6 | 16.6 | — | — | — | — | — | ||||||||||||||||||||
$ | 4,392.4 | $ | 1,523.2 | $ | 217.5 | $ | 531.7 | $ | 96.6 | $ | 83.6 | $ | 1,939.8 | ||||||||||||||
ONEOK Partners | |||||||||||||||||||||||||||
Long-term debt | $ | 4,824.9 | $ | 7.7 | $ | 7.7 | $ | 7.7 | $ | 1,107.7 | $ | 407.7 | $ | 3,286.4 | |||||||||||||
Interest payments on debt | 3,877.2 | 256.8 | 254.9 | 253.6 | 227.4 | 202.8 | 2,681.7 | ||||||||||||||||||||
Operating leases | 3.6 | 0.6 | 1.8 | 0.4 | 0.3 | 0.2 | 0.3 | ||||||||||||||||||||
Firm transportation and storage contracts | 106.6 | 16.3 | 13.2 | 13.0 | 11.7 | 10.1 | 42.3 | ||||||||||||||||||||
Financial and physical derivatives | 79.7 | 79.7 | — | — | — | — | — | ||||||||||||||||||||
Purchase commitments, rights of way and other | 597.0 | 366.8 | 61.5 | 26.1 | 26.1 | 26.1 | 90.4 | ||||||||||||||||||||
$ | 9,489.0 | $ | 727.9 | $ | 339.1 | $ | 300.8 | $ | 1,373.2 | $ | 646.9 | $ | 6,101.1 | ||||||||||||||
Total | $ | 13,881.4 | $ | 2,251.1 | $ | 556.6 | $ | 832.5 | $ | 1,469.8 | $ | 730.5 | $ | 8,040.9 | |||||||||||||
Long-term debt - Long-term debt as reported in our Consolidated Balance Sheets includes unamortized debt discount and the unamortized settlement values of interest-rate swaps.
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Interest payments on debt - Interest expense is calculated by multiplying long-term debt by the respective coupon rates, adjusted for active swaps.
Operating leases - Our operating leases include leases for office space, pipeline equipment and vehicles.
Firm transportation and storage contracts - We are party to fixed-price contracts providing us with firm transportation and storage capacity. However, the costs associated with our Natural Gas Distribution segment’s contracts that are recovered through rates as allowed by the applicable regulatory agency are excluded from the table above.
Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments, physical and financial commodity derivatives. However, the commitments associated with our Natural Gas Distribution segment’s contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the table above. Estimated future variable-price purchase commitments are based on market information at December 31, 2012. Actual future variable-price purchase commitments may vary depending on market prices at the time of delivery. Not included in these amounts are offsetting cash inflows from our ONEOK Partners and Energy Services segments’ product sales and net positive settlements. As market information changes daily and is potentially volatile, these values may change significantly. Additionally, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.
Employee benefit plans - Employee benefit plans include our anticipated contributions to our pension and postretirement benefit plans for 2013. See Note M of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our employee benefit plans.
Purchase commitments, rights of way and other - Purchase commitments include commitments related to ONEOK Partners’ growth capital expenditures and other rights-of-way and contractual commitments. Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Annual Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, liquidity, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Annual Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this Annual Report. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
• | the effects of weather and other natural phenomena, including climate change, on our operations, including energy sales and demand for our services and energy prices; |
• | competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel; |
• | the status of deregulation of retail natural gas distribution; |
• | the capital intensive nature of our businesses; |
• | the profitability of assets or businesses acquired or constructed by us; |
• | our ability to make cost-saving changes in operations; |
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• | risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties; |
• | the uncertainty of estimates, including accruals and costs of environmental remediation; |
• | the timing and extent of changes in energy commodity prices; |
• | the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs; |
• | the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGL volumes, which may include rejected ethane, between producing areas and our facilities; |
• | changes in demand for the use of natural gas and crude oil because of market conditions caused by concerns about global warming; |
• | the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in stock and bond market returns; |
• | our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt, or have other adverse consequences; |
• | actions by rating agencies concerning the credit ratings of ONEOK and ONEOK Partners; |
• | the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, the EPA and CFTC; |
• | our ability to access capital at competitive rates or on terms acceptable to us; |
• | risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling or extended periods of ethane rejection; |
• | the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant; |
• | the impact and outcome of pending and future litigation; |
• | the ability to market pipeline capacity on favorable terms, including the effects of: |
– | future demand for and prices of natural gas, NGLs and crude oil; |
– | competitive conditions in the overall energy market; |
– | availability of supplies of Canadian and United States natural gas and crude oil; and |
– | availability of additional storage capacity; |
• | performance of contractual obligations by our customers, service providers, contractors and shippers; |
• | the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances; |
• | our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems; |
• | the mechanical integrity of facilities operated; |
• | demand for our services in the proximity of our facilities; |
• | our ability to control operating costs; |
• | adverse labor relations; |
• | acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities; |
• | economic climate and growth in the geographic areas in which we do business; |
• | the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets; |
• | the impact of recently issued and future accounting updates and other changes in accounting policies; |
• | the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle East and elsewhere; |
• | the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks; |
• | risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions; |
• | the possible loss of natural gas distribution franchises or other adverse effects caused by the actions of municipalities; |
• | the impact of uncontracted capacity in our assets being greater or less than expected; |
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• | the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates; |
• | the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines; |
• | the efficiency of our plants in processing natural gas and extracting and fractionating NGLs; |
• | the impact of potential impairment charges; |
• | the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting; |
• | our ability to control construction costs and completion schedules of our pipelines and other projects; and |
• | the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference. |
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Item 1A, Risk Factors, in this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Policy and Oversight - We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk-management limits and policies. Our risk oversight committee, comprised of corporate and business-segment officers, oversees all activities related to commodity, price and credit risk management, marketing and trading activities and interest rate risk. The committee also monitors risk metrics including value-at-risk (VAR), position limits and mark-to-market losses. We have a risk-control group that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk-control activities include risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.
Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in commodity prices or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
COMMODITY PRICE RISK
We are exposed to commodity-price risk and the impact of market price fluctuations of natural gas, NGLs and crude oil. Commodity-price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in energy prices, including the impact on seasonal and location price differentials. To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures, physical forward contracts, swaps and options to manage commodity-price risk associated with existing or anticipated purchase and sale agreements, existing physical natural gas or natural gas liquids in storage and location price differentials.
ONEOK Partners
ONEOK Partners is exposed to commodity-price risk as a result of receiving commodities in exchange for its natural gas gathering and processing services. To a lesser extent, ONEOK Partners is exposed to the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to its keep-whole contracts. ONEOK Partners is also exposed to the risk of location price differentials and the cost of third-party transportation to various market locations. As part of ONEOK Partners’ hedging strategy, ONEOK Partners uses commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility in its natural gas gathering and processing business related to natural gas, NGL and condensate price fluctuations.
ONEOK Partners reduces its gross processing spread exposure through a combination of physical and financial hedges. ONEOK Partners utilizes a portion of its percent-of-proceeds equity natural gas as an offset, or natural hedge, to an equivalent portion of its keep-whole shrink requirements. This has the effect of converting ONEOK Partners’ gross processing spread risk to NGL commodity-price risk, and ONEOK Partners then uses financial instruments and physical-forward contracts to hedge the sale of NGLs.
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As of December 31, 2012, ONEOK Partners had $17.6 million of commodity-related derivative assets and $2.5 million of commodity-related derivative liabilities, excluding the impact of netting. The following tables set forth ONEOK Partners’ hedging information for the periods indicated:
Year Ending December 31, 2013 | ||||||||||
Volumes Hedges | Average Price | Percentage Hedged | ||||||||
NGLs (Bbl/d) | 6,439 | $ | 1.19 | / gallon | 45% | |||||
Condensate (Bbl/d) | 2,038 | $ | 2.43 | / gallon | 83% | |||||
Total (Bbl/d) | 8,477 | $ | 1.49 | / gallon | 51% | |||||
Natural gas (MMBtu/d) | 60,014 | $ | 3.79 | / MMBtu | 79% | |||||
Year Ending December 31, 2014 | ||||||||||
Volumes Hedges | Average Price | Percentage Hedged | ||||||||
Condensate (Bbl/d) | 868 | $ | 2.22 | / gallon | 33% | |||||
Natural gas (MMBtu/d) | 36,726 | $ | 4.11 | / MMBtu | 48% | |||||
ONEOK Partners expects its commodity-price risk in its gathering and processing business to increase in the future as volumes increase under POP contracts with our customers. ONEOK Partners’ commodity-price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas, excluding the effects of hedging, and assuming normal operating conditions. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates the following:
• | a $0.01 per gallon change in the composite price of NGLs would change annual net margin by approximately $2.1 million; |
• | a $1.00 per barrel change in the price of crude oil would change annual net margin by approximately $1.1 million; and |
• | a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $2.8 million. |
ONEOK Partners is also exposed to location price differential risk primarily as a result of NGLs in storage, the relative values of the various NGL products to each other, the relative value of NGLs to natural gas and the relative value of NGL purchases at one location and sales at another location. ONEOK Partners utilizes physical-forward contracts to reduce earnings volatility related to NGL price fluctuations in the storage and optimization activities of its natural gas liquids business. ONEOK Partners has not entered into any financial instruments with respect to its natural gas liquids business’ marketing activities.
In addition, ONEOK Partners is exposed to commodity-price risk as its natural gas interstate and intrastate pipelines retain natural gas from its customers for operations or as part of its fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, or store or use natural gas from inventory, which exposes ONEOK Partners to commodity-price risk depending on the regulatory treatment for this activity. To the extent that commodity price risk in its natural gas pipelines business is not mitigated by fuel cost-recovery mechanisms, ONEOK Partners utilizes physical-forward contracts to reduce the impact of price fluctuations related to natural gas. At December 31, 2012, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.
Natural Gas Distribution
Our Natural Gas Distribution segment uses derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect its customers from upward volatility in the market price of natural gas. Gains or losses associated with these derivative instruments are included in, and recoverable through, the monthly purchased-gas cost-adjustment mechanism.
Energy Services
Our Energy Services segment is exposed to commodity-price risk, seasonal and location-price risk and price volatility arising from natural gas in storage, peaking natural gas load requirement contracts, asset management contracts and index-based purchases and sales of natural gas at various market locations. We attempt to mitigate our exposure to commodity price risk through the use of derivative instruments, which, under certain circumstances, are designated as cash flow or fair value
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hedges. We are also exposed to commodity price risk from fixed-price purchases and sales of natural gas, which we hedge with derivative instruments. Both the fixed-price purchases and sales and related derivatives are recorded at fair value.
Fair Value Component of the Energy Marketing and Risk-Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding $27.4 million and $80.7 million of net assets at December 31, 2012 and 2011, respectively, from derivative instruments declared as either fair value or cash flow hedges for the periods indicated:
Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities | |||
(Thousands of dollars) | |||
Net fair value of derivatives outstanding at January 1, 2011 | $ | 8,441 | |
Derivatives reclassified or otherwise settled during the period | (11,378 | ) | |
Fair value of new derivatives entered into during the period | 70,141 | ||
Other changes in fair value | (54,595 | ) | |
Net fair value of derivatives outstanding at December 31, 2011 | 12,609 | ||
Derivatives reclassified or otherwise settled during the period | (15,074 | ) | |
Fair value of new derivatives entered into during the period | 178 | ||
Other changes in fair value | 7,320 | ||
Net fair value of derivatives outstanding at December 31, 2012 (a) | $ | 5,033 | |
(a) - The maturities of derivatives are based on injection and withdrawal periods from April through March, which is consistent with our business strategy. The maturities are as follows: $2.6 million matures through March 2013 and $2.4 million matures through March 2015. | |||
The change in the net fair value of derivatives outstanding includes the effect of settled energy contracts and current period changes resulting primarily from newly originated transactions and the impact of market movements on the fair value of energy marketing and risk management assets and liabilities.
For further discussion of fair value measurements and trading activities and assumptions used in our trading activities, see the “Estimates and Critical Accounting Policies” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. Also, see Notes C and D of the Notes to Consolidated Financial Statements in this Annual Report.
VAR Disclosure of Commodity Price Risk - We measure commodity-price risk in our Energy Services segment using a VAR methodology, which estimates the expected maximum loss of our portfolio over a specified time horizon within a given confidence interval. Our VAR calculations are based on the Monte Carlo approach. The quantification of commodity-price risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance and to determine risk thresholds. The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation. Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements. Other assumptions include a distribution of prices and historical data to calculate volatility and price correlations. We rely on VAR to determine the potential reduction in the portfolio values arising from changes in market conditions over a defined period. While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR. Different assumptions and approximations could produce materially different VAR estimates.
Our VAR exposure represents an estimate of potential losses that would be recognized due to adverse commodity-price movements in our Energy Services segment’s portfolio of derivative financial instruments, physical commodity contracts, leased transport, storage capacity contracts and natural gas in storage. A one-day time horizon and a 95-percent confidence level are used in our VAR data. Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our derivative financial instruments, physical contracts and natural gas in storage. VAR information should be evaluated in light of these assumptions and the methodology’s other limitations.
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The potential impact on our future earnings, as measured by VAR, was $1.5 million and $2.7 million at December 31, 2012 and 2011, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated:
Years Ended December 31, | ||||||||
Value-at-Risk | 2012 | 2011 | ||||||
(Millions of dollars) | ||||||||
Average | $ | 2.6 | $ | 3.0 | ||||
High | $ | 4.0 | $ | 6.6 | ||||
Low | $ | 1.4 | $ | 1.2 | ||||
Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in our portfolio during the year. The decrease in average VAR for 2012, compared with 2011, was due primarily to a reduction in volume of leased storage and transportation capacity.
To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position either favorably or unfavorably. As a result, we cannot predict with precision the impact risk-management decisions may have on our business, operating results or financial position.
INTEREST-RATE RISK
General - We are subject to the risk of interest-rate fluctuation in the normal course of business. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates. At December 31, 2012, the interest rate on all of ONEOK’s and ONEOK Partners’ long-term debt was fixed, and ONEOK Partners had forward-starting interest-rate swaps that have been designated as cash flow hedges of the variability of interest payments on a portion of a forecasted debt issuance that may result from changes in the benchmark interest rate before the debt is issued.
COUNTERPARTY CREDIT RISK
ONEOK and ONEOK Partners assess the creditworthiness of their counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
ONEOK, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows present fairly, in all material respects, the financial position of ONEOK, Inc. and its subsidiaries (the Company) at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A in the Company’s Form 10-K for the year ended December 31, 2012. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 26, 2013
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ONEOK, Inc. and Subsidiaries | ||||||||||||
CONSOLIDATED STATEMENTS OF INCOME | ||||||||||||
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars, except per share amounts) | ||||||||||||
Revenues | $ | 12,632,559 | $ | 14,805,794 | $ | 12,678,791 | ||||||
Cost of sales and fuel | 10,281,718 | 12,425,435 | 10,616,621 | |||||||||
Net margin | 2,350,841 | 2,380,359 | 2,062,170 | |||||||||
Operating expenses | ||||||||||||
Operations and maintenance | 806,087 | 813,666 | 740,881 | |||||||||
Depreciation and amortization | 335,844 | 312,160 | 307,224 | |||||||||
Goodwill impairment | 10,255 | — | — | |||||||||
General taxes | 102,891 | 94,657 | 90,032 | |||||||||
Total operating expenses | 1,255,077 | 1,220,483 | 1,138,137 | |||||||||
Gain (loss) on sale of assets | 6,736 | (963 | ) | 18,619 | ||||||||
Operating income | 1,102,500 | 1,158,913 | 942,652 | |||||||||
Equity earnings from investments (Note O) | 123,024 | 127,246 | 101,880 | |||||||||
Allowance for equity funds used during construction | 13,648 | 2,335 | 1,018 | |||||||||
Other income | 12,504 | 1,410 | 11,527 | |||||||||
Other expense | (4,925 | ) | (9,336 | ) | (11,067 | ) | ||||||
Interest expense (net of capitalized interest of $41,776, $23,960 and $4,888, respectively) | (302,305 | ) | (297,006 | ) | (292,232 | ) | ||||||
Income before income taxes | 944,446 | 983,562 | 753,778 | |||||||||
Income taxes (Note N) | (215,195 | ) | (226,048 | ) | (213,720 | ) | ||||||
Income from continuing operations | 729,251 | 757,514 | 540,058 | |||||||||
Income from discontinued operations, net of tax (Note B) | 762 | 2,230 | 1,272 | |||||||||
Gain on sale of discontinued operations, net of tax (Note B) | 13,517 | — | — | |||||||||
Net income | 743,530 | 759,744 | 541,330 | |||||||||
Less: Net income attributable to noncontrolling interests | 382,911 | 399,150 | 206,698 | |||||||||
Net income attributable to ONEOK | $ | 360,619 | $ | 360,594 | $ | 334,632 | ||||||
Amounts attributable to ONEOK: | ||||||||||||
Income from continuing operations | $ | 346,340 | $ | 358,364 | $ | 333,360 | ||||||
Income from discontinued operations | 14,279 | 2,230 | 1,272 | |||||||||
Net Income | $ | 360,619 | $ | 360,594 | $ | 334,632 | ||||||
Basic earnings per share (Note K): | ||||||||||||
Income from continuing operations | $ | 1.68 | $ | 1.71 | $ | 1.57 | ||||||
Income from discontinued operations | 0.07 | 0.01 | — | |||||||||
Net Income | $ | 1.75 | $ | 1.72 | $ | 1.57 | ||||||
Diluted earnings per share (Note K): | ||||||||||||
Income from continuing operations | $ | 1.64 | $ | 1.67 | $ | 1.55 | ||||||
Income from discontinued operations | 0.07 | 0.01 | — | |||||||||
Net Income | $ | 1.71 | $ | 1.68 | $ | 1.55 | ||||||
Average shares (thousands) | ||||||||||||
Basic | 206,140 | 209,344 | 212,736 | |||||||||
Diluted | 210,710 | 214,498 | 215,570 | |||||||||
Dividends declared per share of common stock | $ | 1.27 | $ | 1.08 | $ | 0.91 | ||||||
See accompanying Notes to Consolidated Financial Statements. | ||||||||||||
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ONEOK, Inc. and Subsidiaries | ||||||||||||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | ||||||||||||
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Net income | $ | 743,530 | $ | 759,744 | $ | 541,330 | ||||||
Other comprehensive income (loss), net of tax | ||||||||||||
Unrealized gains (losses) on energy marketing and risk management assets/ liabilities, net of tax of $(10,601), $(8,670) and $(43,039), respectively | 22,826 | (19,828 | ) | 85,623 | ||||||||
Realized gains in net income, net of tax of $10,327, $53,714 and $29,278, respectively | (49,499 | ) | (84,025 | ) | (48,117 | ) | ||||||
Unrealized holding gains (losses) on available-for-sale securities, net of tax of $(30), $242 and $44, respectively | 47 | (384 | ) | (70 | ) | |||||||
Change in pension and postretirement benefit plan liability, net of tax of $6,977, $16,298 and $7,570, respectively | (11,061 | ) | (25,837 | ) | (12,001 | ) | ||||||
Other, net of tax of $0, $50 and $(45), respectively | — | (79 | ) | 71 | ||||||||
Total other comprehensive income (loss), net of tax | (37,687 | ) | (130,153 | ) | 25,506 | |||||||
Comprehensive income | 705,843 | 629,591 | 566,836 | |||||||||
Less: Comprehensive income attributable to noncontrolling interests | 355,901 | 366,316 | 222,393 | |||||||||
Comprehensive income attributable to ONEOK | $ | 349,942 | $ | 263,275 | $ | 344,443 | ||||||
See accompanying Notes to Consolidated Financial Statements. | ||||||||||||
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ONEOK, Inc. and Subsidiaries | ||||||||
CONSOLIDATED BALANCE SHEETS | ||||||||
December 31, | December 31, | |||||||
2012 | 2011 | |||||||
Assets | (Thousands of dollars) | |||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 583,618 | $ | 65,953 | ||||
Accounts receivable, net | 1,349,371 | 1,339,933 | ||||||
Gas and natural gas liquids in storage | 517,014 | 549,915 | ||||||
Commodity imbalances | 90,211 | 63,452 | ||||||
Energy marketing and risk management assets (Notes C and D) | 48,577 | 40,280 | ||||||
Other current assets | 175,869 | 185,143 | ||||||
Assets of discontinued operations (Note B) | — | 74,136 | ||||||
Total current assets | 2,764,660 | 2,318,812 | ||||||
Property, plant and equipment | ||||||||
Property, plant and equipment | 13,088,991 | 11,177,934 | ||||||
Accumulated depreciation and amortization | 2,974,651 | 2,733,601 | ||||||
Net property, plant and equipment (Note E) | 10,114,340 | 8,444,333 | ||||||
Investments and other assets | ||||||||
Goodwill and intangible assets (Note F) | 996,206 | 1,014,127 | ||||||
Investments in unconsolidated affiliates (Note O) | 1,221,405 | 1,223,398 | ||||||
Other assets | 758,664 | 695,965 | ||||||
Total investments and other assets | 2,976,275 | 2,933,490 | ||||||
Total assets | $ | 15,855,275 | $ | 13,696,635 | ||||
See accompanying Notes to Consolidated Financial Statements. | ||||||||
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ONEOK, Inc. and Subsidiaries | ||||||||
CONSOLIDATED BALANCE SHEETS | ||||||||
December 31, | December 31, | |||||||
2012 | 2011 | |||||||
Liabilities and equity | (Thousands of dollars) | |||||||
Current liabilities | ||||||||
Current maturities of long-term debt (Note H) | $ | 10,855 | $ | 364,391 | ||||
Notes payable (Note G) | 817,170 | 841,982 | ||||||
Accounts payable | 1,333,489 | 1,341,718 | ||||||
Commodity imbalances | 272,436 | 202,206 | ||||||
Energy marketing and risk management liabilities (Notes C and D) | 9,990 | 137,680 | ||||||
Other current liabilities | 369,054 | 345,383 | ||||||
Liabilities of discontinued operations (Note B) | — | 12,815 | ||||||
Total current liabilities | 2,812,994 | 3,246,175 | ||||||
Long-term debt, excluding current maturities (Note H) | 6,515,372 | 4,529,551 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes | 1,592,802 | 1,446,591 | ||||||
Other deferred credits | 701,657 | 674,586 | ||||||
Total deferred credits and other liabilities | 2,294,459 | 2,121,177 | ||||||
Commitments and contingencies (Note Q) | ||||||||
Equity (Note I) | ||||||||
ONEOK shareholders’ equity: | ||||||||
Common stock, $0.01 par value: | ||||||||
authorized 600,000,000 shares; issued 245,811,180 shares and outstanding 204,935,043 shares at December 31, 2012; issued 245,809,848 shares and outstanding 206,509,960 shares at December 31, 2011 | 2,458 | 2,458 | ||||||
Paid-in capital | 1,324,698 | 1,417,185 | ||||||
Accumulated other comprehensive loss (Note J) | (216,798 | ) | (206,121 | ) | ||||
Retained earnings | 2,059,024 | 1,960,374 | ||||||
Treasury stock, at cost: 40,876,137 shares at December 31, 2012 and 39,299,888 shares at December 31, 2011 | (1,039,773 | ) | (935,323 | ) | ||||
Total ONEOK shareholders’ equity | 2,129,609 | 2,238,573 | ||||||
Noncontrolling interests in consolidated subsidiaries | 2,102,841 | 1,561,159 | ||||||
Total equity | 4,232,450 | 3,799,732 | ||||||
Total liabilities and equity | $ | 15,855,275 | $ | 13,696,635 | ||||
See accompanying Notes to Consolidated Financial Statements. | ||||||||
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ONEOK, Inc. and Subsidiaries | ||||||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Operating activities | ||||||||||||
Net income | $ | 743,530 | $ | 759,744 | $ | 541,330 | ||||||
Depreciation and amortization | 335,852 | 312,288 | 307,317 | |||||||||
Impairment of goodwill | 10,255 | — | — | |||||||||
Gain on sale of discontinued operations | (13,517 | ) | — | — | ||||||||
Equity earnings from investments | (123,024 | ) | (127,246 | ) | (101,880 | ) | ||||||
Distributions received from unconsolidated affiliates | 120,442 | 132,741 | 96,958 | |||||||||
Deferred income taxes | 229,398 | 256,688 | 142,303 | |||||||||
Share-based compensation expense | 36,692 | 66,371 | 24,372 | |||||||||
Allowance for equity funds used during construction | (13,648 | ) | (2,335 | ) | (1,018 | ) | ||||||
Loss (gain) on sale of assets | (6,736 | ) | 963 | (18,619 | ) | |||||||
Other | 27,982 | (1,471 | ) | 4,153 | ||||||||
Changes in assets and liabilities: | ||||||||||||
Accounts receivable | (14,774 | ) | (55,861 | ) | 92,469 | |||||||
Gas and natural gas liquids in storage | 33,343 | 65,845 | (164,722 | ) | ||||||||
Accounts payable | (30,981 | ) | 102,621 | (43,883 | ) | |||||||
Commodity imbalances, net | 43,471 | (54,886 | ) | (15,316 | ) | |||||||
Energy marketing and risk management assets and liabilities | (174,953 | ) | (31,999 | ) | 112,827 | |||||||
Fair value of firm commitments | (6,003 | ) | (22,252 | ) | (105,084 | ) | ||||||
Pension and postretirement benefits | (57,073 | ) | (29,863 | ) | (68,719 | ) | ||||||
Other assets and liabilities | (149,313 | ) | (11,376 | ) | 31,554 | |||||||
Cash provided by operating activities | 990,943 | 1,359,972 | 834,042 | |||||||||
Investing activities | ||||||||||||
Capital expenditures (less allowance for equity funds used during construction) | (1,866,153 | ) | (1,336,067 | ) | (582,748 | ) | ||||||
Proceeds from sale of discontinued operations, net of cash sold | 32,946 | — | — | |||||||||
Contributions to unconsolidated affiliates | (30,768 | ) | (64,491 | ) | (1,331 | ) | ||||||
Distributions received from unconsolidated affiliates | 35,299 | 23,644 | 17,847 | |||||||||
Proceeds from sale of assets | 12,240 | 1,288 | 428,908 | |||||||||
Other | 2,237 | 4,000 | 2,968 | |||||||||
Cash used in investing activities | (1,814,199 | ) | (1,371,626 | ) | (134,356 | ) | ||||||
Financing activities | ||||||||||||
Borrowing (repayment) of notes payable, net | (24,812 | ) | 285,127 | (325,015 | ) | |||||||
Issuance of debt, net of discounts | 1,994,693 | 1,295,450 | — | |||||||||
Long-term debt financing costs | (15,036 | ) | (10,986 | ) | — | |||||||
Repayment of debt | (361,464 | ) | (727,562 | ) | (262,715 | ) | ||||||
Repurchase of common stock | (150,000 | ) | (300,108 | ) | (7 | ) | ||||||
Issuance of common stock | 15,969 | 17,906 | 20,912 | |||||||||
Issuance of common units, net of issuance costs | 459,587 | — | 322,701 | |||||||||
Dividends paid | (261,969 | ) | (227,020 | ) | (193,542 | ) | ||||||
Distributions to noncontrolling interests | (324,906 | ) | (277,375 | ) | (260,385 | ) | ||||||
Cash provided by (used in) financing activities | 1,332,062 | 55,432 | (698,051 | ) | ||||||||
Change in cash and cash equivalents | 508,806 | 43,778 | 1,635 | |||||||||
Change in cash and cash equivalents included in discontinued operations | 8,859 | (8,166 | ) | (2,211 | ) | |||||||
Change in cash and cash equivalents from continuing operations | 517,665 | 35,612 | (576 | ) | ||||||||
Cash and cash equivalents at beginning of period | 65,953 | 30,341 | 30,917 | |||||||||
Cash and cash equivalents at end of period | $ | 583,618 | $ | 65,953 | $ | 30,341 | ||||||
Supplemental cash flow information: | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 439,398 | $ | 278,162 | $ | 298,354 | ||||||
Cash paid (refunds received) for income taxes | $ | 872 | $ | (68,696 | ) | $ | 16,841 | |||||
See accompanying Notes to Consolidated Financial Statements. | ||||||||||||
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ONEOK, Inc. and Subsidiaries | |||||||||||||||
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY | |||||||||||||||
ONEOK Shareholders’ Equity | |||||||||||||||
Common Stock Issued | Common Stock | Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | ||||||||||||
(Shares) | (Thousands of dollars) | ||||||||||||||
January 1, 2010 | 244,788,030 | $ | 2,448 | $ | 1,321,116 | $ | (118,613 | ) | |||||||
Net income | — | — | — | — | |||||||||||
Other comprehensive income | — | — | — | 9,811 | |||||||||||
Repurchase of common stock | — | — | — | — | |||||||||||
Common stock issued | 843,242 | 8 | 19,596 | — | |||||||||||
Common stock dividends - $0.91 per share | — | — | — | — | |||||||||||
Issuance of common units of ONEOK Partners | — | — | 50,731 | — | |||||||||||
Distributions to noncontrolling interests | — | — | — | — | |||||||||||
Other | — | — | — | — | |||||||||||
December 31, 2010 | 245,631,272 | 2,456 | 1,391,443 | (108,802 | ) | ||||||||||
Net income | — | — | — | — | |||||||||||
Other comprehensive loss | — | — | — | (97,319 | ) | ||||||||||
Repurchase of common stock | — | — | — | — | |||||||||||
Common stock issued | 178,576 | 2 | 25,742 | — | |||||||||||
Common stock dividends - $1.08 per share | — | — | — | — | |||||||||||
Distributions to noncontrolling interests | — | — | — | — | |||||||||||
December 31, 2011 | 245,809,848 | 2,458 | 1,417,185 | (206,121 | ) | ||||||||||
Net income | — | — | — | — | |||||||||||
Other comprehensive loss | — | — | — | (10,677 | ) | ||||||||||
Repurchase of common stock | — | — | — | — | |||||||||||
Common stock issued | 1,332 | — | (23,404 | ) | — | ||||||||||
Common stock dividends - $1.27 per share | — | — | — | — | |||||||||||
Issuance of common units of ONEOK Partners | — | — | (51,100 | ) | — | ||||||||||
Distributions to noncontrolling interests | — | — | — | — | |||||||||||
Other | — | — | (17,983 | ) | — | ||||||||||
December 31, 2012 | 245,811,180 | $ | 2,458 | $ | 1,324,698 | $ | (216,798 | ) | |||||||
See accompanying Notes to Consolidated Financial Statements. | |||||||||||||||
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ONEOK, Inc. and Subsidiaries | ||||||||||||||||
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY | ||||||||||||||||
(Continued) | ||||||||||||||||
ONEOK Shareholders’ Equity | ||||||||||||||||
Retained Earnings | Treasury Stock | Noncontrolling Interest in Consolidated Subsidiaries | Total Equity | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
January 1, 2010 | $ | 1,685,710 | $ | (683,467 | ) | $ | 1,238,268 | $ | 3,445,462 | |||||||
Net income | 334,632 | — | 206,698 | 541,330 | ||||||||||||
Other comprehensive income | — | — | 15,695 | 25,506 | ||||||||||||
Repurchase of common stock | — | (7 | ) | — | (7 | ) | ||||||||||
Common stock issued | — | 20,200 | — | 39,804 | ||||||||||||
Common stock dividends - $0.91 per share | (193,542 | ) | — | — | (193,542 | ) | ||||||||||
Issuance of common units of ONEOK Partners | — | — | 271,970 | 322,701 | ||||||||||||
Distributions to noncontrolling interests | — | — | (260,385 | ) | (260,385 | ) | ||||||||||
Other | — | — | (28 | ) | (28 | ) | ||||||||||
December 31, 2010 | 1,826,800 | (663,274 | ) | 1,472,218 | 3,920,841 | |||||||||||
Net income | 360,594 | — | 399,150 | 759,744 | ||||||||||||
Other comprehensive loss | — | — | (32,834 | ) | (130,153 | ) | ||||||||||
Repurchase of common stock | — | (300,108 | ) | — | (300,108 | ) | ||||||||||
Common stock issued | — | 28,059 | — | 53,803 | ||||||||||||
Common stock dividends - $1.08 per share | (227,020 | ) | — | — | (227,020 | ) | ||||||||||
Distributions to noncontrolling interests | — | — | (277,375 | ) | (277,375 | ) | ||||||||||
December 31, 2011 | 1,960,374 | (935,323 | ) | 1,561,159 | 3,799,732 | |||||||||||
Net income | 360,619 | — | 382,911 | 743,530 | ||||||||||||
Other comprehensive loss | — | — | (27,010 | ) | (37,687 | ) | ||||||||||
Repurchase of common stock | — | (150,000 | ) | — | (150,000 | ) | ||||||||||
Common stock issued | — | 45,550 | — | 22,146 | ||||||||||||
Common stock dividends - $1.27 per share | (261,969 | ) | — | — | (261,969 | ) | ||||||||||
Issuance of common units of ONEOK Partners | — | — | 510,687 | 459,587 | ||||||||||||
Distributions to noncontrolling interests | — | — | (324,906 | ) | (324,906 | ) | ||||||||||
Other | — | — | — | (17,983 | ) | |||||||||||
December 31, 2012 | $ | 2,059,024 | $ | (1,039,773 | ) | $ | 2,102,841 | $ | 4,232,450 | |||||||
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ONEOK, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations - We are a diversified energy company and successor to the company founded in 1906 known as Oklahoma Natural Gas Company. We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.” We are the sole general partner and own 43.4 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest publicly traded master limited partnerships.
We have divided our operations into three reportable business segments as follows:
• | ONEOK Partners; |
• | Natural Gas Distribution; and |
• | Energy Services. |
ONEOK Partners is a diversified master limited partnership involved in the gathering, processing, storage and transportation of natural gas in the United States. In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers. To aid in understanding the important business and financial characteristics of our ONEOK Partners segment, the following describes its business with reference to its underlying activities.
ONEOK Partners’ natural gas gathering and processing business is engaged in the gathering and processing of natural gas produced from crude oil and natural gas wells, primarily in the Mid-Continent and Rocky Mountain regions. These regions include the NGL-rich Cana-Woodford Shale, Woodford Shale and Granite Wash formations; the Mississippian Lime area of Oklahoma and Kansas; Hugoton and Central Kansas Uplift Basins of Kansas; the Williston Basin of Montana and North Dakota that includes the oil-producing, NGL-rich Bakken Shale and Three Forks areas; and the Powder River Basin of Wyoming. In the Powder River Basin, the natural gas that ONEOK Partners gathers is coal-bed methane, or dry, natural gas that does not require processing or NGL extraction in order to be marketable. Dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.
ONEOK Partners’ natural gas pipeline business operates interstate and intrastate natural gas transmission pipelines and natural gas storage facilities. ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states, including the Cana-Woodford, Granite Wash and Mississippian Lime areas. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas, which are connected to its intrastate natural gas pipeline assets.
ONEOK Partners’ natural gas liquids business consists of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas. Its natural gas liquids business owns or has an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Wyoming, Colorado, North Dakota and Montana and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. It also owns FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect its Mid-Continent assets with Midwest markets, including Chicago, Illinois. ONEOK Partners’ natural gas liquids business also owns and operates truck and rail-loading and unloading facilities that interconnect with its fractionation and pipeline assets.
Our Natural Gas Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our natural gas distribution companies serve wholesale and public authority customers.
Our Energy Services segment is a provider of nonuniform natural gas supply and risk-management services for natural gas and electric utilities and commercial and industrial customers with natural gas needs. We use a network of leased storage and transportation capacity to supply natural gas to our customers. This network connects the major supply and demand centers throughout the United States and into Canada and, coupled with our industry knowledge and market intelligence, allows us to provide our customers with customized services in a more efficient and reliable manner than they can achieve independently. Our customers are primarily LDCs, electric utilities and commercial and industrial end-users. Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable.
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Consolidation - Our consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control or are the primary beneficiary. We have recorded noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the portion of ONEOK Partners that we do not own. We reflected our ownership interest in ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss). The remaining portion is reflected as an adjustment to noncontrolling interests in consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment. The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows. See Note O for disclosures of our unconsolidated affiliates.
Use of Estimates - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, gas purchased expense for natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.
We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.
Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.
While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. Inputs into our fair value estimates include commodity-exchange prices, over-the-counter quotes, volatility, historical correlations of pricing data and LIBOR and other liquid money-market instrument rates. We also utilize internally developed basis curves that incorporate observable and unobservable market data. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.
In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitor the credit default swap markets. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.
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The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements.
Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
• | Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities; |
• | Level 2 - Significant observable pricing inputs other than quoted prices included within Level 1 that are, either directly or indirectly, observable as of the reporting date. Essentially, this represents inputs that are derived principally from or corroborated by observable market data; and |
• | Level 3 - May include one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include our own internal data. |
We recognize transfers into and out of Level 3 as of the end of each reporting period. Transfers into Level 3 represent existing assets or liabilities that were categorized previously at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety. See Note C for additional disclosures of our fair value measurements.
Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.
Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through its facilities. ONEOK Partners’ natural gas liquids operations record revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the period services are provided. Revenue for ONEOK Partners’ natural gas pipelines and a portion of its natural gas liquids operations is recognized based upon contracted capacity and contracted volumes transported and stored under service agreements in the period services are provided.
Our Natural Gas Distribution segment’s major industrial and commercial natural gas distribution customers are invoiced at the end of each month. All natural gas distribution residential customers and some commercial customers are invoiced on a cyclical basis throughout the month, and we accrue unbilled revenues at the end of each month.
Our revenues from sales to our Energy Services segment’s wholesale customers are accrued in the month of physical delivery based on contracted sales price and estimated volumes. Demand payments received for requirements contracts are recognized in the period in which the service is provided. Our fixed-price physical sales are accounted for as derivatives and are recorded at fair value. See discussion below in “Derivative and Risk Management Activities” for additional information.
Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Outstanding customer receivables are reviewed regularly for possible nonpayment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. At December 31, 2012 and 2011, our allowance for doubtful accounts was not material.
Inventories - The values of current natural gas and NGLs in storage are determined using the lower of weighted-average cost or market method. Noncurrent natural gas and NGLs are classified as property and valued at cost. Materials and supplies are valued at average cost.
Commodity Imbalances - Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at fair value. Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty. In turn, we deliver NGL products back to the customer and charge them gathering and fractionation
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fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties. These net exchange receivables and payables are settled with movements of NGL products rather than with cash. Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement.
Derivatives and Risk Management Activities - We record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.
If certain conditions are met, we may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currency. Certain nontrading derivative transactions, which are economic hedges of our accrual transactions such as our storage and transportation contracts, do not qualify for hedge accounting treatment.
The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
Recognition and Measurement | ||||
Accounting Treatment | Balance Sheet | Income Statement | ||
Normal purchases and normal sales | - | Fair value not recorded | - | Change in fair value not recognized in earnings |
Mark-to-market | - | Recorded at fair value | - | Change in fair value recognized in earnings |
Cash flow hedge | - | Recorded at fair value | - | Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings |
- | Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss) | - | Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings | |
Fair value hedge | - | Recorded at fair value | - | The gain or loss on the derivative instrument is recognized in earnings |
- | Change in fair value of the hedged item is recorded as an adjustment to book value | - | Change in fair value of the hedged item is recognized in earnings | |
Gains or losses associated with the fair value of derivative instruments entered into by our Natural Gas Distribution segment are included in, and recoverable through, the monthly purchased-gas cost mechanism.
We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our cash flow and fair value hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.
The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts. All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income. The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and nonderivative contracts are reported on a gross basis. Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.
Revenues in our Consolidated Statements of Income include financial trading margins, as well as certain physical natural gas transactions with our trading counterparties. Revenues and cost of sales and fuel from such physical transactions are reported on a net basis.
Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same category as the cash flows from the related hedged items in our Consolidated Statements of Cash Flows.
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See Notes C and D for more discussion of our fair value measurements and risk management and hedging activities using derivatives.
Property, Plant and Equipment - Our properties are stated at cost, including AFUDC. Generally, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or retirement of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense.
The interest portion of AFUDC represents the cost of borrowed funds used to finance construction activities. We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense.
The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.
Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances. We periodically conduct depreciation studies to assess the economic lives of our assets. For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed. For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations.
Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.
See Note E for disclosures of our property, plant and equipment.
Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill and indefinite-lived intangible assets for impairment at least annually as of July 1. As a result of the decline in natural gas prices and its effect on location and seasonal price differentials, we performed an interim impairment assessment of our Energy Services segment’s goodwill balance as of March 31, 2012. As a result of that assessment, goodwill with a carrying amount of 10.3 million was written down to its implied fair value of zero, with a resulting impairment charge of 10.3 million recorded in 2012 earnings. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services.
Our goodwill impairment analysis performed as of July 1, 2012, did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets. There were no impairment charges resulting from our 2011 or 2010 annual impairment tests.
As part of our goodwill impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill. In the first step, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds the implied fair value of the goodwill, we will record an impairment charge.
To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply multiples to forecasted cash flows. The multiples used are
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consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows over a period of years.
As part of our indefinite-lived intangible asset impairment test, we compare the estimated fair value of our indefinite-lived intangible asset with its book value. The fair value of our indefinite-lived intangible asset is estimated using the market approach. Under the market approach, we apply multiples to forecasted cash flows of the assets associated with our indefinite-lived intangible asset. The multiples used are consistent with historical asset transactions. We determined that there were no impairments to our indefinite-lived intangible asset in 2012, 2011 or 2010.
We assess our long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no asset impairments in 2012, 2011 or 2010.
For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry our equity method investments to determine whether current events or circumstances warrant adjustments to our carrying value. We determined that there were no impairments to our investments in unconsolidated affiliates in 2012, 2011 or 2010.
Low natural gas prices and the relatively higher crude oil and NGL prices compared with natural gas on a heating-value basis have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the Powder River Basin. The reduced development activities and natural production declines in the Powder River Basin have resulted in lower volumes available to be gathered. While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects. Bighorn Gas Gathering, in which ONEOK Partners owns a 49-percent equity interest, has operations in the Powder River Basin. Due to declines in volumes gathered on Bighorn Gas Gathering’s system, ONEOK Partners tested its investment for impairment. The carrying amount of ONEOK Partners’ investment as of December 31, 2012, was $90.4 million, which includes $53.4 million in equity method goodwill. ONEOK Partners estimated the fair value of its investment in Bighorn Gas Gathering using an income approach, which discounted the cash flows of ONEOK Partners investment’s underlying assets with a discount rate reflective of its cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures. The fair value exceeded the carrying value; therefore, no impairment was recorded.
A continued decline in natural gas volumes in the Powder River Basin may reduce ONEOK Partners’ ability to recover the carrying value of its assets and equity investments in this area and could result in noncash charges to earnings. A 10-percent decline in the fair value of ONEOK Partners’ investment in Bighorn Gas Gathering would result in a noncash impairment charge. For ONEOK Partners’ other equity method investments with operations in the Powder River Basin with carrying values of approximately $200 million, which includes approximately $130 million in equity method goodwill, ONEOK Partners did not identify current events or circumstances that warranted an impairment analysis or an adjustment to its carrying values. ONEOK Partners is not able to reasonably estimate a range of potential future charges, as many of the assumptions that would be used in a fair value model are dependent upon events such as commodity prices, producers’ drilling and production activity and effects of government regulations and policies.
Our impairment tests require the use of assumptions and estimates such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.
See Notes E, F and O for our goodwill and intangible assets, long-lived assets and investment in unconsolidated affiliates disclosures.
Regulation - Our natural gas distribution operations and ONEOK Partners’ intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. ONEOK Partners’ interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC. In Kansas and Texas, natural gas storage may be regulated by the state and the FERC for certain types of services. Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance for regulated operations. During the rate-making process, regulatory authorities set the framework for what we can
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charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time, as opposed to expensing such costs as incurred. Examples include costs for fuel and fuel losses, acquisition costs and contributions in aid of construction. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer:
• | established by independent, third-party regulators; |
• | designed to recover the specific entity’s costs of providing regulated services; and |
• | set at levels that will recover our costs when considering the demand and competition for our services. |
At December 31, 2012 and 2011, we recorded regulatory assets of approximately $585.0 million and $539.7 million, respectively, which are being recovered as a result of various approved rate proceedings or are expected to be recovered. Of these amounts, approximately $499.4 million and $466.6 million relate to our pension and postretirement benefit plans at December 31, 2012 and 2011, respectively, which are discussed in Note M. Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 40 years. These assets are reflected in other assets on our Consolidated Balance Sheets.
Pension and Postretirement Employee Benefits - We have defined benefit retirement plans covering certain full-time employees. We sponsor welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. Our actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the costs and liabilities we recognize. See Note M for more discussion of pension and postretirement employee benefits.
Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of assets and liabilities and carry-forward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse. The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates. For all other operations, the effect is recognized in income in the period that includes the enactment date. We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.
We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute. During 2012, 2011 and 2010, our tax positions did not require an establishment of a material reserve.
We file numerous consolidated and separate income tax returns with federal tax authorities of the United States and Canada, along with the tax authorities of several states. There are no United States federal audits or statute waivers at this time. See Note N for additional discussion of income taxes.
Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our assets because the settlement dates are indeterminable. For our assets that we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and amortization expense are immaterial to our consolidated financial statements.
In accordance with long-standing regulatory treatment, we collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and
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amortization. These removal costs are nonlegal obligations; however, the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory liability. Historically, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify this amount; rather, these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, significant uncertainty exists regarding the ultimate determination of this liability, pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory requirements, and the liability may be adjusted as more information is obtained. We record the estimated nonlegal asset removal obligation in noncurrent liabilities in other deferred credits on our Consolidated Balance Sheets. To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note Q for additional discussion of contingencies.
Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures. We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.
Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period. Diluted EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period plus potentially dilutive components. The dilutive components are calculated based on the dilutive effect for each quarter. For fiscal-year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.
Recently Issued Accounting Standards Update - In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS. This new guidance changes some fair value measurement principles and disclosure requirements. We adopted this guidance with our March 31, 2012, Quarterly Report, and the impact was not material. See Note C for information on our fair value measurements.
In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which provides two options for presenting items of net income, other comprehensive income and total comprehensive income by creating either one continuous statement of comprehensive income or two separate consecutive statements, and requires certain other disclosures. In December 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” which deferred certain presentation requirements in ASU 2011-05 for items reclassified out of accumulated other comprehensive income. We adopted this guidance, except for the portions deferred by ASU 2011-12, with our March 31, 2012, Quarterly Report, and the impact was not material.
In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source. We will adopt this guidance with our March 31, 2013, Quarterly Report.
In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment,” which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Under the amendments in this update, an entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may also resume performing the qualitative assessment in any subsequent period. We adopted this guidance beginning with our July 1, 2012, goodwill impairment test, and it did not impact our financial position or results of operations.
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In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-01 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and IFRS related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance will be effective for interim and annual periods beginning on January 1, 2013, and will be applied retrospectively for all comparative periods presented. The adoption of this guidance beginning with our March 31, 2013, Quarterly Report will not affect our financial condition, results of operations or cash flows.
In July 2012, the FASB issued ASU 2012-02, “Testing Indefinite-lived Intangible Assets for Impairment,” which allows companies to perform a “qualitative” assessment to determine whether further impairment testing of indefinite-lived intangible assets is necessary. Under the revised standard, an entity is not required to calculate the fair value of an indefinite-lived intangible asset and perform the quantitative impairment test unless the entity determines that it is more likely than not that the asset is impaired. An entity has the option to bypass the qualitative assessment and perform the quantitative impairment test for any indefinite-lived intangible assets in any period. We expect the impact of this guidance to be immaterial when we adopt it for our annual assessments beginning in 2013.
B. DISCONTINUED OPERATIONS
On February 1, 2012, we sold ONEOK Energy Marketing Company, our Natural Gas Distribution segment’s retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital. We received net proceeds of approximately $32.9 million and recognized a gain on the sale of approximately $13.5 million, net of taxes of $8.3 million. The proceeds from the sale were used to reduce short-term borrowings. The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report. All prior periods presented have been recast to reflect the discontinued operations.
The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:
One Month Ended | Years Ended | |||||||||||
January 31, | December 31, | |||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Revenues | $ | 27,607 | $ | 313,371 | $ | 351,260 | ||||||
Cost of sales and fuel | 25,961 | 302,561 | 340,888 | |||||||||
Net margin | 1,646 | 10,810 | 10,372 | |||||||||
Operating costs | 408 | 7,147 | 8,914 | |||||||||
Depreciation and amortization | 8 | 128 | 93 | |||||||||
Operating income | 1,230 | 3,535 | 1,365 | |||||||||
Other income (expense), net | — | (50 | ) | 21 | ||||||||
Income taxes | (468 | ) | (1,255 | ) | (114 | ) | ||||||
Income from discontinued operations, net | $ | 762 | $ | 2,230 | $ | 1,272 | ||||||
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The following table discloses the major classes of discontinued assets and liabilities included on our Consolidated Balance Sheets for the periods indicated:
December 31, | ||||
2011 | ||||
Assets | (Thousands of dollars) | |||
Cash and cash equivalents | $ | 8,859 | ||
Accounts receivable, net | 47,967 | |||
Gas in storage | 2,101 | |||
Energy marketing and risk management assets | 15,016 | |||
Other assets | 193 | |||
Assets of discontinued operations | $ | 74,136 | ||
Liabilities | ||||
Accounts payable | $ | 11,435 | ||
Energy marketing and risk management liabilities | 629 | |||
Other liabilities | 751 | |||
Liabilities of discontinued operations | $ | 12,815 | ||
At December 31, 2011, the liabilities of our discontinued operations exclude $45.7 million of intercompany payables due to its parent or other affiliates.
C. FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for our continuing and discontinued operations for the periods indicated:
December 31, 2012 | ||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total - Gross | Netting | Total - Net | |||||||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||
Derivatives (a) | ||||||||||||||||||||||||
Commodity contracts | ||||||||||||||||||||||||
Financial contracts | $ | 69,957 | $ | 10,780 | $ | 7,107 | $ | 87,844 | $ | (51,602 | ) | $ | 36,242 | |||||||||||
Physical contracts | — | 2,083 | 2,032 | 4,115 | (151 | ) | 3,964 | |||||||||||||||||
Interest-rate contracts | — | 10,923 | — | 10,923 | — | 10,923 | ||||||||||||||||||
Total derivatives | 69,957 | 23,786 | 9,139 | 102,882 | (51,753 | ) | 51,129 | |||||||||||||||||
Trading securities (b) | 5,978 | — | — | 5,978 | — | 5,978 | ||||||||||||||||||
Available-for-sale investment securities (c) | 2,027 | — | — | 2,027 | — | 2,027 | ||||||||||||||||||
Total assets | $ | 77,962 | $ | 23,786 | $ | 9,139 | $ | 110,887 | $ | (51,753 | ) | $ | 59,134 | |||||||||||
Liabilities | ||||||||||||||||||||||||
Derivatives (a) | ||||||||||||||||||||||||
Commodity contracts | ||||||||||||||||||||||||
Financial contracts | $ | (35,172 | ) | $ | (1,737 | ) | $ | (7,177 | ) | $ | (44,086 | ) | $ | 33,878 | $ | (10,208 | ) | |||||||
Physical contracts | — | — | (279 | ) | (279 | ) | 151 | (128 | ) | |||||||||||||||
Total derivatives | (35,172 | ) | (1,737 | ) | (7,456 | ) | (44,365 | ) | 34,029 | (10,336 | ) | |||||||||||||
Fair value of firm commitments (d) | — | — | (1,280 | ) | (1,280 | ) | — | (1,280 | ) | |||||||||||||||
Total liabilities | $ | (35,172 | ) | $ | (1,737 | ) | $ | (8,736 | ) | $ | (45,645 | ) | $ | 34,029 | $ | (11,616 | ) | |||||||
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2012, we held $17.7 million of cash collateral and had posted $4.5 million of cash collateral with various counterparties.
(b) - Included in our Consolidated Balance Sheets as other current assets.
(c) - Included in our Consolidated Balance Sheets as other assets.
(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred assets.
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December 31, 2011 | ||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total - Gross | Netting | Total - Net | |||||||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||
Derivatives (a) | ||||||||||||||||||||||||
Commodity contracts | ||||||||||||||||||||||||
Financial contracts | $ | 545,247 | $ | 13,874 | $ | 32,931 | $ | 592,052 | $ | (568,888 | ) | $ | 23,164 | |||||||||||
Physical contracts | — | 23,879 | 14,916 | 38,795 | (355 | ) | 38,440 | |||||||||||||||||
Total derivatives | 545,247 | 37,753 | 47,847 | 630,847 | (569,243 | ) | 61,604 | |||||||||||||||||
Trading securities (b) | 5,749 | — | — | 5,749 | — | 5,749 | ||||||||||||||||||
Available-for-sale investment securities (c) | 1,949 | — | — | 1,949 | — | 1,949 | ||||||||||||||||||
Total assets | $ | 552,945 | $ | 37,753 | $ | 47,847 | $ | 638,545 | $ | (569,243 | ) | $ | 69,302 | |||||||||||
Liabilities | ||||||||||||||||||||||||
Derivatives (a) | ||||||||||||||||||||||||
Commodity contracts | ||||||||||||||||||||||||
Financial contracts | $ | (479,073 | ) | $ | (6,498 | ) | $ | (20,995 | ) | $ | (506,566 | ) | $ | 497,253 | $ | (9,313 | ) | |||||||
Physical contracts | — | (261 | ) | (1,748 | ) | (2,009 | ) | 355 | (1,654 | ) | ||||||||||||||
Interest-rate contracts | — | (128,666 | ) | — | (128,666 | ) | — | (128,666 | ) | |||||||||||||||
Total derivatives | (479,073 | ) | (135,425 | ) | (22,743 | ) | (637,241 | ) | 497,608 | (139,633 | ) | |||||||||||||
Fair value of firm commitments (d) | — | — | (7,283 | ) | (7,283 | ) | — | (7,283 | ) | |||||||||||||||
Total liabilities | $ | (479,073 | ) | $ | (135,425 | ) | $ | (30,026 | ) | $ | (644,524 | ) | $ | 497,608 | $ | (146,916 | ) | |||||||
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2011, we held $73.3 million of cash collateral and had posted $1.7 million of cash collateral with various counterparties.
(b) - Included in our Consolidated Balance Sheets as other current assets.
(c) - Included in our Consolidated Balance Sheets as other assets.
(d) - Included in our Consolidated Balance Sheets as other current liabilities and other deferred credits.
The December 31, 2011, table above includes balances for ONEOK Energy Marketing Company that have been reflected as discontinued operations in our Consolidated Balance Sheet. At December 31, 2011, we had $15.0 million in derivative assets and $0.6 million in derivative liabilities related to this discontinued operation.
Our Level 1 fair value amounts are based on unadjusted quoted prices in active markets including NYMEX-settled prices and actively quoted prices for equity securities. These balances are comprised predominantly of exchange-traded derivative contracts for natural gas and crude oil. Also included in Level 1 are equity securities.
Our Level 2 fair value amounts are based on significant observable pricing inputs, such as NYMEX-settled prices for natural gas and crude oil, and financial models that utilize implied forward LIBOR yield curves for interest-rate swaps.
Our Level 3 fair value amounts are based on inputs that may include one or more unobservable inputs including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. These balances categorized as Level 3 are comprised of derivatives for natural gas and natural gas liquids. Also included in Level 3 are the fair values of firm commitments. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material. The significant unobservable inputs used are the unpublished forward basis and index curves. Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.
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The following tables set forth the reconciliation of our Level 3 fair value measurements for the periods indicated:
Derivative Assets (Liabilities) | Fair Value of Firm Commitments | Total | ||||||||||
(Thousands of dollars) | ||||||||||||
January 1, 2012 | $ | 25,104 | $ | (7,283 | ) | $ | 17,821 | |||||
Total realized/unrealized gains (losses): | ||||||||||||
Included in earnings (a) | (13,503 | ) | 6,003 | (7,500 | ) | |||||||
Included in other comprehensive income (loss) | (5,587 | ) | — | (5,587 | ) | |||||||
Sale of discontinued operations | (3,636 | ) | — | (3,636 | ) | |||||||
Transfers out of Level 3 | (695 | ) | — | (695 | ) | |||||||
December 31, 2012 | $ | 1,683 | $ | (1,280 | ) | $ | 403 | |||||
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2012 (a) | $ | 1,971 | $ | (112 | ) | $ | 1,859 | |||||
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.
Derivative Assets (Liabilities) | Fair Value of Firm Commitments | Total | ||||||||||
(Thousands of dollars) | ||||||||||||
January 1, 2011 | $ | 49,266 | $ | (29,536 | ) | $ | 19,730 | |||||
Total realized/unrealized gains (losses): | ||||||||||||
Included in earnings (a) | (28,425 | ) | 22,253 | (6,172 | ) | |||||||
Included in other comprehensive income (loss) | 5,443 | — | 5,443 | |||||||||
Transfers into Level 3 | 1,428 | — | 1,428 | |||||||||
Transfers out of Level 3 | (2,608 | ) | — | (2,608 | ) | |||||||
December 31, 2011 | $ | 25,104 | $ | (7,283 | ) | $ | 17,821 | |||||
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2011 (a) | $ | 21,349 | $ | (6,581 | ) | $ | 14,768 | |||||
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.
Realized/unrealized gains (losses) include the realization of our derivative contracts through maturity and changes in fair value of our hedged firm commitments. We recognize transfers into and out of the levels in the fair value hierarchy as of the end of each reporting period. We had no transfers into or out of Level 1 during the periods presented. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.
Our Level 3 fair value measurements based on unobservable inputs, excluding the portion of our fair value measurements based on third-party pricing information without adjustment, are not material at December 31, 2012.
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable is equal to book value, due to the short-term nature of these items.
Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1. Our notes payable are classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market. The estimated fair value of our consolidated long-term debt, including current maturities, was $7.5 billion and $5.6 billion at December 31, 2012 and 2011, respectively. The book value of long-term debt, including current maturities, was $6.5 billion and $4.9 billion at December 31, 2012 and 2011, respectively. The estimated fair value of the aggregate of ONEOK’s and ONEOK Partners’ senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities. Our consolidated long-term debt is classified as Level 2.
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D. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES
Our Energy Services and ONEOK Partners segments are exposed to various risks that we manage by periodically entering into derivative instruments. These risks include the following:
• | Commodity-price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil. We use commodity derivative instruments such as futures, physical forward contracts, swaps and options to reduce the commodity-price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage. Commodity price volatility may have a significant impact on the fair value of our derivative instruments as of a given date; |
• | Basis risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price differentials between pipeline receipt and delivery locations. Our firm transportation capacity allows us to purchase natural gas at a pipeline receipt point and sell natural gas at a pipeline delivery point. As market conditions permit, our Energy Services segment periodically enters into basis swaps between the transportation receipt and delivery points in order to protect the fair value of these location price differentials related to our firm commitments; |
• | Currency exchange-rate risk - As a result of our Energy Services segment’s activities in Canada, we are exposed to the risk of loss in cash flows and future earnings from adverse changes in currency exchange rates on our commodity purchases and sales, primarily related to our firm transportation and storage contracts that are transacted in a currency other than our functional currency, the United States dollar. To reduce our exposure to exchange-rate fluctuations, we use physical forward transactions, which result in an actual two-way flow of currency on the settlement date in which we exchange United States dollars for Canadian dollars with another party; and |
• | Interest-rate risk - We are also subject to fluctuations in interest rates. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. |
The following derivative instruments are used to manage our exposure to these risks:
• | Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations; |
• | Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or NGLs for future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties; |
• | Swaps - Exchange of one or more payments based on the value of one or more commodities. This transfers the financial risk associated with a future change in value between the counterparties of the transaction without also conveying ownership interest in the asset or liability; and |
• | Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity, at a fixed price, within a specified period of time. Options may either be standardized and exchange traded or customized and nonexchange traded. |
Our objectives for entering into such contracts include but are not limited to:
• | reducing the variability of cash flows by locking in the price for all or a portion of anticipated index-based physical purchases and sales, transportation fuel requirements, asset management transactions and customer-related business activities; |
• | locking in a price differential to protect the fair value between transportation receipt and delivery points and to protect the fair value of natural gas or NGLs that are purchased in one month and sold in a later month; |
• | reducing our exposure to fluctuations in interest and foreign currency exchange rates; and |
• | reducing variability in cash flows from changes in interest rates associated with forecasted debt issuances. |
Our Energy Services segment also enters into derivative contracts for financial trading purposes primarily to capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market liquidity inefficiencies, which allow us to capture additional margin. Financial trading activities are executed generally using financially settled derivatives and are normally short term in nature.
With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity prices can impact our financial position and results of operations. The net open positions are managed actively, and the impact of the changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year.
Our Natural Gas Distribution segment also uses derivative instruments to hedge the cost of a portion of anticipated natural gas purchases during the winter heating months to protect our customers from upward volatility in the market price of natural
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gas. The use of these derivative instruments and the associated recovery of these costs have been approved by the OCC, KCC and regulatory authorities in certain of our Texas jurisdictions.
ONEOK entered into forward-starting interest-rate swaps designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. ONEOK had interest-rate swaps with notional values totaling $500 million at December 31, 2011. In January 2012, ONEOK entered into additional interest-rate swaps with notional amounts totaling $200 million. Upon issuance in January 2012 of our $700 million, 4.25-percent senior notes due 2022, ONEOK settled all $700 million of its interest-rate swaps and realized a loss of $44.1 million in accumulated other comprehensive income (loss) that will be amortized to interest expense over the term of the related debt.
ONEOK Partners entered into forward-starting interest-rate swaps designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. At December 31, 2011, ONEOK Partners had interest-rate swaps with notional values totaling $750 million. During the year ended December 31, 2012, ONEOK Partners entered into additional interest-rate swaps with notional amounts totaling $650 million. Upon ONEOK Partners’ debt issuance in September 2012, ONEOK Partners settled $1 billion of its interest-rate swaps and realized a loss of $124.9 million in accumulated other comprehensive income (loss) that will be amortized to interest expense over the term of the related debt. At December 31, 2012, ONEOK Partners’ remaining interest-rate swaps with notional amounts totaling $400 million have settlement dates greater than 12 months.
Fair Values of Derivative Instruments - The following table sets forth the fair values of our derivative instruments for our continuing and discontinued operations for the periods indicated:
December 31, 2012 | December 31, 2011 | ||||||||||||||||
Fair Values of Derivatives (a) | Fair Values of Derivatives (a) | ||||||||||||||||
Assets | (Liabilities) | Assets | (Liabilities) | ||||||||||||||
(Thousands of dollars) | |||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||
Commodity contracts | |||||||||||||||||
Financial contracts | $ | 47,516 | (b) | $ | (4,885 | ) | $ | 184,184 | (c) | $ | (73,346 | ) | |||||
Physical contracts | 56 | (126 | ) | 62 | (344 | ) | |||||||||||
Interest-rate contracts | 10,923 | — | — | (128,666 | ) | ||||||||||||
Total derivatives designated as hedging instruments | 58,495 | (5,011 | ) | 184,246 | (202,356 | ) | |||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||
Commodity contracts | |||||||||||||||||
Nontrading instruments | |||||||||||||||||
Financial contracts | 24,970 | (25,009 | ) | 295,948 | (323,170 | ) | |||||||||||
Physical contracts | 4,059 | (153 | ) | 38,733 | (1,665 | ) | |||||||||||
Trading instruments | |||||||||||||||||
Financial contracts | 15,358 | (14,192 | ) | 111,920 | (110,050 | ) | |||||||||||
Total derivatives not designated as hedging instruments | 44,387 | (39,354 | ) | 446,601 | (434,885 | ) | |||||||||||
Total derivatives | $ | 102,882 | $ | (44,365 | ) | $ | 630,847 | $ | (637,241 | ) | |||||||
(a) - Included on a net basis in energy marketing and risk-management assets and liabilities, other assets and other deferred credits on our Consolidated Balance Sheets.
(b) - Includes $16.9 million of derivative net assets and ineffectiveness associated with cash flow hedges of inventory related to certain financial contracts that were used to hedge forecasted purchases and sales of natural gas. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).
(c) - Includes $88.9 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).
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Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for our continuing and discontinued operations for the periods indicated:
December 31, 2012 | December 31, 2011 | ||||||||||||||
Contract Type | Purchased/ Payor | Sold/ Receiver | Purchased/ Payor | Sold/ Receiver | |||||||||||
Derivatives designated as hedging instruments: | |||||||||||||||
Cash flow hedges | |||||||||||||||
Fixed price | |||||||||||||||
-Natural gas (Bcf) | Futures, forwards and swaps | — | (85.1 | ) | 40.7 | (135.3 | ) | ||||||||
-Crude oil and NGLs (MMBbl) | Futures, forwards and swaps | — | (1.1 | ) | — | (2.9 | ) | ||||||||
Basis | |||||||||||||||
-Natural gas (Bcf) | Futures, forwards and swaps | — | (56.3 | ) | 3.2 | (82.8 | ) | ||||||||
Interest-rate contracts (Millions of dollars) | Forward-starting swaps | $ | 400.0 | — | $ | 1,250.0 | — | ||||||||
Fair value hedges | |||||||||||||||
Basis | |||||||||||||||
-Natural gas (Bcf) | Futures, forwards and swaps | 59.1 | (59.1 | ) | 76.5 | (77.0 | ) | ||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||
Fixed price | |||||||||||||||
-Natural gas (Bcf) | Futures, forwards and swaps | 60.7 | (60.4 | ) | 312.7 | (313.0 | ) | ||||||||
Options | 102.1 | (100.8 | ) | 33.6 | (14.3 | ) | |||||||||
Basis | |||||||||||||||
-Natural gas (Bcf) | Futures, forwards and swaps | 80.2 | (81.7 | ) | 216.9 | (219.3 | ) | ||||||||
Index | |||||||||||||||
-Natural gas (Bcf) | Futures, forwards and swaps | 20.3 | (22.3 | ) | 29.3 | (22.1 | ) | ||||||||
These notional amounts are used to summarize the volume of financial instruments; however, they do not reflect the extent to which the positions offset one another and consequently do not reflect our actual exposure to market or credit risk.
Cash Flow Hedges - Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at December 31, 2012, includes gains of approximately $0.9 million, net of tax, related to these hedges that will be recognized within the next 24 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $0.4 million in net gains over the next 12 months, and we will recognize net gains of $0.5 million thereafter. The remaining amounts deferred in accumulated other comprehensive income (loss) associated with derivative instruments are primarily attributable to our interest-rate swaps of which losses of $14.6 million will be reclassified into earnings during the next 12 months as the hedged items affect earnings.
For the year ended December 31, 2012, net margin in our Consolidated Statement of Income includes losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas. As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceed the amount expected to be recovered through sales of that inventory after considering related sales hedges, which requires reclassification of the loss from accumulated other comprehensive loss to current period earnings. In 2011, cost of sales and fuel in our Consolidated Statements of Income included $91.1 million reflecting an adjustment to natural gas inventory at the lower of cost or market value. We also reclassified $91.1 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.
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The following table sets forth the effect of cash flow hedges recognized in other comprehensive income (loss) for the periods indicated:
Derivatives in Cash Flow Hedging Relationships | Years Ended December 31, | |||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Commodity contracts | $ | 62,898 | $ | 117,508 | $ | 128,662 | ||||||
Interest-rate contracts | (29,471 | ) | (128,666 | ) | — | |||||||
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion) | $ | 33,427 | $ | (11,158 | ) | $ | 128,662 | |||||
The following tables set forth the effect of cash flow hedges on our Consolidated Statements of Income for the periods indicated:
Derivatives in Cash Flow Hedging Relationships | Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion) | Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||||
(Thousands of dollars) | ||||||||||||||
Commodity contracts | Revenues | $ | 140,862 | $ | 48,601 | $ | 68,209 | |||||||
Commodity contracts | Cost of sales and fuel | (73,881 | ) | 89,618 | 9,158 | |||||||||
Interest-rate contracts | Interest expense | (7,155 | ) | (480 | ) | 28 | ||||||||
Total gain reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion) | $ | 59,826 | $ | 137,739 | $ | 77,395 | ||||||||
Ineffectiveness related to our cash flow hedges was not material for the years ended December 31, 2012, 2011 and 2010. In the event that it becomes probable that a forecasted transaction will not occur, we will discontinue cash flow hedge treatment, which will affect earnings. For the years ended December 31, 2012, 2011 and 2010, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable.
Other Derivative Instruments - The following table sets forth the effect of our derivative instruments that are not part of a hedging relationship on our Consolidated Statements of Income for our continuing and discontinued operations for the periods indicated:
Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) | Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||||
(Thousands of dollars) | ||||||||||||||
Commodity contracts - trading | Revenues | $ | 2,413 | $ | 1,796 | $ | 5,710 | |||||||
Commodity contracts - non-trading (a) | Cost of sales and fuel | 5,956 | 16,178 | 5,371 | ||||||||||
Foreign exchange contracts | Revenues | — | — | 18 | ||||||||||
Total gain recognized in income on derivatives | $ | 8,369 | $ | 17,974 | $ | 11,099 | ||||||||
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Natural Gas Distribution segment.
Our Natural Gas Distribution segment held natural gas call options with premiums totaling $9.6 million and $10.0 million at December 31, 2012 and 2011, respectively. The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism. We recorded losses of $5.9 million, $14.5 million and $25.5 million for the years ended December 31, 2012, 2011 and 2010, respectively, which are deferred as part of our unrecovered purchased-gas costs.
Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements that had been designated as fair value hedges. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings from the amortization of terminated swaps for 2012, 2011 and 2010, were $1.7 million, $4.3 million and $10.2 million, respectively.
Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to certain firm transportation commitments. Cost of sales and fuel in our Consolidated Statements of Income includes gains of $0.4 million, $14.6 million and $2.4 million for the years ended December 31, 2012, 2011 and 2010, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include gains of $0.5 million, and losses of $13.8 million and $2.7 million for the years ended December 31, 2012, 2011 and 2010, respectively, to recognize the change in fair value of
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the related hedged firm commitments. The ineffectiveness related to these hedges was not material for the years ended December 31, 2012, 2011 and 2010.
Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We have counterparties whose credit is not rated, and for those customers we use internally developed credit ratings.
Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s. If our credit ratings on senior unsecured long-term debt were to decline below investment grade, we would be in violation of these provisions, and the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position as of December 31, 2012, was $2.6 million. If the contingent features underlying these agreements were triggered on December 31, 2012, we would have been required to post an additional $2.6 million of collateral to our counterparties.
The counterparties to our derivative contracts consist primarily of major energy companies, LDCs, electric utilities, financial institutions and commercial and industrial end-users. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
At December 31, 2012, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial and utility sectors.
E. PROPERTY, PLANT AND EQUIPMENT
The following table sets forth our property, plant and equipment by property type, for the periods indicated:
Estimated Useful Lives (Years) | December 31, 2012 | December 31, 2011 | ||||||||
(Thousands of dollars) | ||||||||||
Non-Regulated | ||||||||||
Gathering pipelines and related equipment | 5 to 40 | $ | 1,638,037 | $ | 1,350,227 | |||||
Processing and fractionation and related equipment | 5 to 40 | 1,625,146 | 1,294,586 | |||||||
Storage and related equipment | 5 to 54 | 335,237 | 299,610 | |||||||
Transmission pipelines and related equipment | 22 to 54 | 311,038 | 182,863 | |||||||
General plant and other | 2 to 42 | 348,636 | 288,445 | |||||||
Construction work in process | — | 881,788 | 725,944 | |||||||
Regulated | ||||||||||
Natural gas distribution pipelines and related equipment | 15 to 80 | 3,512,660 | 3,309,876 | |||||||
Storage and related equipment | 5 to 54 | 136,938 | 136,971 | |||||||
Natural gas transmission pipelines and related equipment | 5 to 77 | 1,796,683 | 1,771,752 | |||||||
Natural gas liquids transmission pipelines and related equipment | 5 to 80 | 1,490,511 | 1,436,500 | |||||||
General plant and other | 2 to 85 | 309,119 | 291,642 | |||||||
Construction work in process | — | 703,198 | 89,518 | |||||||
Property, plant and equipment | 13,088,991 | 11,177,934 | ||||||||
Accumulated depreciation and amortization - non-regulated | (954,398 | ) | (811,644 | ) | ||||||
Accumulated depreciation and amortization - regulated | (2,020,253 | ) | (1,921,957 | ) | ||||||
Net property, plant and equipment | $ | 10,114,340 | $ | 8,444,333 | ||||||
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The average depreciation rates for our regulated property are set forth, by segment, in the following table for the periods indicated:
Years Ended December 31, | ||||||
Regulated Property | 2012 | 2011 | 2010 | |||
ONEOK Partners | 1.9% - 2.2% | 1.9% - 2.2% | 1.9% - 2.2% | |||
Natural Gas Distribution | 2.0% - 3.0% | 2.0% - 2.9% | 2.1% - 2.8% | |||
ONEOK Partners incurred liabilities for construction work in process that had not been paid at December 31, 2012, 2011 and 2010 of $216.5 million, $152.0 million and $56.2 million, respectively. Such amounts are not included in capital expenditures (less allowance for equity funds used during construction) on the Consolidated Statements of Cash Flows.
F. GOODWILL AND INTANGIBLE ASSETS
Goodwill - The following table sets forth our goodwill by segment for the periods indicated:
December 31, | December 31, | |||||||
2012 | 2011 | |||||||
(Thousands of dollars) | ||||||||
ONEOK Partners | $ | 433,535 | $ | 433,535 | ||||
Natural Gas Distribution | 157,953 | 157,953 | ||||||
Energy Services | — | 10,255 | ||||||
Total goodwill | $ | 591,488 | $ | 601,743 | ||||
Intangible Assets - The following table sets forth the gross carrying amount and accumulated amortization of intangible assets for the periods indicated:
December 31, | December 31, | |||||||
2012 | 2011 | |||||||
(Thousands of dollars) | ||||||||
Gross intangible assets | $ | 462,214 | $ | 462,214 | ||||
Accumulated amortization | (57,496 | ) | (49,830 | ) | ||||
Net intangible assets | $ | 404,718 | $ | 412,384 | ||||
As a result of our interim impairment assessment of our Energy Services segment’s goodwill, goodwill with a carrying amount of $10.3 million was written down to its implied fair value of zero, with a resulting impairment charge of $10.3 million recorded in 2012 earnings. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. There were no impairment charges resulting from our 2011 or 2010 annual impairment tests.
At December 31, 2012 and 2011, our ONEOK Partners segment has $249.2 million and $256.8 million, respectively, of intangible assets related primarily to contracts acquired through acquisition, which are being amortized over an aggregate weighted-average period of 40 years. The remaining intangible asset balance has an indefinite life. Amortization expense for intangible assets for 2012, 2011 and 2010 was $7.7 million each year, and the aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million.
G. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE
ONEOK Credit Agreement - The ONEOK Credit Agreement, which is scheduled to expire in April 2016, contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 67.5 percent at the end of any calendar quarter, limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets, a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships. The ONEOK Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends. The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners. In the event of a breach of certain covenants by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become due and payable immediately.
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At December 31, 2012, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 52.2 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.
Under the terms of the ONEOK Credit Agreement, ONEOK may request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Credit Agreement is available for general corporate purposes, including repayment of ONEOK’s commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Credit Agreement. The ONEOK Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in our credit rating. Borrowings, if any, will accrue at LIBOR plus 150 basis points, and the annual facility fee is 25 basis points based on our current credit rating.
At December 31, 2012, ONEOK had $817.2 million of commercial paper outstanding and $1.9 million in letters of credit issued, leaving approximately $380.9 million of credit available under the ONEOK Credit Agreement.
The weighted-average interest rate on ONEOK’s short-term debt outstanding was 0.46 percent and 0.50 percent at December 31, 2012 and 2011, respectively.
ONEOK Partners Credit Agreement - The ONEOK Partners Credit Agreement contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter of the acquisition and the two following quarters. Upon breach of certain covenants by ONEOK Partners in the ONEOK Partners Credit Agreement, amounts outstanding under the ONEOK Partners Credit Agreement, if any, may become due and payable immediately. At December 31, 2012, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.0 to 1, and we were in compliance with all covenants under the ONEOK Partners Credit Agreement.
The ONEOK Partners Credit Agreement includes a $100 million sublimit for the issuance of standby letters of credit and also features an option that allows ONEOK Partners to request an increase in the size of the facility to an aggregate of $1.7 billion from $1.2 billion by either commitments from new lenders or increased commitments from existing lenders. The ONEOK Partners Credit Agreement is available for general partnership purposes, including repayment of ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under our commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement. At December 31, 2012 and 2011, ONEOK Partners had no commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners Credit Agreement.
The ONEOK Partners Credit Agreement contains provisions for an applicable margin rate and an annual facility fee, both of which adjust with changes in ONEOK Partners credit rating. Borrowings, if any, will accrue at LIBOR plus 130 basis points, and the annual facility fee is 20 basis points based on ONEOK Partners current credit rating. ONEOK Partners Credit Agreement is guaranteed fully and unconditionally by the Intermediate Partnership. Borrowings under the ONEOK Partners Credit Agreement are nonrecourse to ONEOK.
In August 2012, ONEOK Partners extended the maturity of the ONEOK Partners Credit Agreement from August 1, 2016, to August 1, 2017, pursuant to an extension agreement between ONEOK Partners and its lenders.
Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners.
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H. LONG-TERM DEBT
All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness. The following table sets forth our long-term debt for the periods indicated:
December 31, | December 31, | |||||||
2012 | 2011 | |||||||
(Thousands of dollars) | ||||||||
ONEOK | ||||||||
$400,000 at 5.2% due 2015 | $ | 400,000 | $ | 400,000 | ||||
$700,000 at 4.25% due 2022 | 700,000 | — | ||||||
$100,000 at 6.5% due 2028 | 87,662 | 87,735 | ||||||
$100,000 at 6.875% due 2028 | 100,000 | 100,000 | ||||||
$400,000 at 6.0% due 2035 | 400,000 | 400,000 | ||||||
Other | 1,528 | 1,858 | ||||||
Total ONEOK senior notes payable | 1,689,190 | 989,593 | ||||||
ONEOK Partners | ||||||||
$350,000 at 5.90% due 2012 | — | 350,000 | ||||||
$650,000 at 3.25% due 2016 | 650,000 | 650,000 | ||||||
$450,000 at 6.15% due 2016 | 450,000 | 450,000 | ||||||
$400,000 at 2.0% due 2017 | 400,000 | — | ||||||
$500,000 at 8.625% due 2019 | 500,000 | 500,000 | ||||||
$900,000 at 3.375% due 2022 | 900,000 | — | ||||||
$600,000 at 6.65% due 2036 | 600,000 | 600,000 | ||||||
$600,000 at 6.85% due 2037 | 600,000 | 600,000 | ||||||
$650,000 at 6.125% due 2041 | 650,000 | 650,000 | ||||||
Guardian Pipeline | ||||||||
Average 7.85%, due 2022 | 74,857 | 85,919 | ||||||
Total ONEOK Partners senior notes payable | 4,824,857 | 3,885,919 | ||||||
Total long-term notes payable | 6,514,047 | 4,875,512 | ||||||
Unamortized portion of terminated swaps | 27,058 | 28,776 | ||||||
Unamortized debt discount | (14,878 | ) | (10,346 | ) | ||||
Current maturities | (10,855 | ) | (364,391 | ) | ||||
Long-term debt | $ | 6,515,372 | $ | 4,529,551 | ||||
The aggregate maturities of long-term debt outstanding for the years 2013 through 2017 are shown below:
ONEOK | ONEOK Partners | Guardian Pipeline | Total | |||||||||||||
(Millions of dollars) | ||||||||||||||||
2013 | $ | 3.2 | $ | — | $ | 7.7 | $ | 10.9 | ||||||||
2014 | $ | 3.0 | $ | — | $ | 7.7 | $ | 10.7 | ||||||||
2015 | $ | 403.0 | $ | — | $ | 7.7 | $ | 410.7 | ||||||||
2016 | $ | 3.0 | $ | 1,100.0 | $ | 7.7 | $ | 1,110.7 | ||||||||
2017 | $ | 3.0 | $ | 400.0 | $ | 7.7 | $ | 410.7 | ||||||||
Additionally, our senior notes due 2028 (6.5 percent) are callable at par at our option from now until maturity.
ONEOK Debt Repayments - In 2011, ONEOK repaid $400 million of maturing senior notes and redeemed $90.5 million of 6.4-percent senior notes with available cash and short-term borrowings.
ONEOK Debt Issuance - In January 2012, we completed an underwritten public offering of $700 million, 4.25-percent senior notes due 2022. The net proceeds from the offering, after deducting underwriting discounts and offering expenses, of approximately $694.3 million were used to repay amounts outstanding under our $1.2 billion commercial paper program and for general corporate purposes.
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ONEOK Debt Covenants - The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.
ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest. ONEOK may redeem its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date. Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.
ONEOK Partners’ Debt Issuance and Maturities - In September 2012, ONEOK Partners completed an underwritten public offering of $1.3 billion of senior notes, consisting of $400 million, 2.0-percent senior notes due 2017 and $900 million, 3.375-percent senior notes due 2022. A portion of the net proceeds from the offering of approximately $1.3 billion were used to repay amounts outstanding under ONEOK Partners’ commercial paper program, and the balance will be used for general partnership purposes, including but not limited to capital expenditures.
ONEOK Partners repaid its $350 million, 5.9-percent senior notes upon maturity in April 2012 with a portion of the proceeds from its March 2012 equity issuance.
In January 2011, ONEOK Partners completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering of approximately $1.3 billion were used to repay amounts outstanding under ONEOK Partners’ commercial paper program, to repay the $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.
ONEOK Partners’ Debt Covenants - ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.
ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes on the same terms as its other senior notes. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries. ONEOK Partners’ senior notes are nonrecourse to ONEOK.
ONEOK Partners’ Debt Guarantee - ONEOK Partners’ senior notes are guaranteed on a senior unsecured basis by the Intermediate Partnership. The Intermediate Partnership’s guarantee is full and unconditional, subject to certain customary automatic release provisions. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness. ONEOK Partners has no significant assets or operations other than its investment in the Intermediate Partnership, which is also consolidated. At December 31, 2012, the Intermediate Partnership held the equity
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of ONEOK Partners’ subsidiaries, as well as a 50-percent interest in Northern Border Pipeline. ONEOK Partners’ long-term debt is nonrecourse to ONEOK.
Guardian Pipeline Senior Notes - These senior notes were issued under a master shelf agreement dated November 8, 2001, with certain financial institutions. Principal payments are due quarterly through 2022. These senior notes contain financial covenants that require the maintenance of certain ratios defined in the master shelf agreement based on Guardian Pipeline’s financial position and results of operations. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. At December 31, 2012, Guardian Pipeline was in compliance with its financial covenants.
Interest-rate Swaps - See Note D for a discussion of our interest-rate swaps.
Other - We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.
I. EQUITY
Series A and B Convertible Preferred Stock - There are no shares of Series A or Series B Preferred Stock currently issued or outstanding.
Series C Preferred Stock - The Series C Preferred Stock (Series C) was issuable in connection with our now expired ONEOK Rights Agreement, which was designed to protect our shareholders from coercive or unfair takeover tactics. No shares of Series C were issued, and the ONEOK Rights Agreement expired February 4, 2013, and was not renewed.
Common Stock - At December 31, 2012, we had approximately 360.9 million shares of authorized and unreserved common stock available for issuance.
Stock Split - In June 2012, we completed a two-for-one split of our common stock. We have adjusted all share and per-share amounts contained herein to be presented on a post-split basis.
Dividends - Dividends paid totaled $262.0 million, $227.0 million and $193.5 million for 2012, 2011 and 2010, respectively. The following table sets forth the quarterly dividends per share declared and paid on our common stock for the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
First Quarter | $ | 0.305 | $ | 0.26 | $ | 0.22 | ||||||
Second Quarter | $ | 0.305 | $ | 0.26 | $ | 0.22 | ||||||
Third Quarter | $ | 0.33 | $ | 0.28 | $ | 0.23 | ||||||
Fourth Quarter | $ | 0.33 | $ | 0.28 | $ | 0.24 | ||||||
Total | $ | 1.27 | $ | 1.08 | $ | 0.91 | ||||||
Additionally, a quarterly dividend of $0.36 per share was declared in January 2013, payable in the first quarter of 2013.
Stock Repurchase Program - In September 2012, we repurchased approximately 3.4 million shares of our common stock for $150 million.
Our three-year stock repurchase program was authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock, subject to the limitation that purchases will not exceed $300 million in any one calendar year. Following our $150 million repurchase in September 2012 and our $300 million repurchase in 2011, an additional $300 million may yet be purchased should we elect to do so pursuant to our three-year repurchase program.
See Note P for a discussion of ONEOK Partners’ issuance of common units and distributions to noncontrolling interests.
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J. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following table sets forth the balance in accumulated other comprehensive income (loss) for the periods indicated:
Unrealized Gains (Losses) on Energy Marketing and Risk Management Assets/Liabilities | Unrealized Holding Gains (Losses) on Investment Securities | Pension and Postretirement Benefit Plan Obligations | Accumulated Other Comprehensive Income (Loss) | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
January 1, 2011 | $ | 15,731 | $ | 1,371 | $ | (125,904 | ) | $ | (108,802 | ) | ||||||
Other comprehensive income (loss) attributable to ONEOK | (71,098 | ) | (384 | ) | (25,837 | ) | (97,319 | ) | ||||||||
December 31, 2011 | (55,367 | ) | 987 | (151,741 | ) | (206,121 | ) | |||||||||
Other comprehensive income (loss) attributable to ONEOK | 337 | 47 | (11,061 | ) | (10,677 | ) | ||||||||||
December 31, 2012 | $ | (55,030 | ) | $ | 1,034 | $ | (162,802 | ) | $ | (216,798 | ) | |||||
K. EARNINGS PER SHARE
The following tables set forth the computation of basic and diluted EPS from continuing operations for the periods indicated:
Year Ended December 31, 2012 | |||||||||||
Income | Shares | Per Share Amount | |||||||||
(Thousands, except per share amounts) | |||||||||||
Basic EPS from continuing operations | |||||||||||
Income from continuing operations attributable to ONEOK available for common stock | $ | 346,340 | 206,140 | $ | 1.68 | ||||||
Diluted EPS from continuing operations | |||||||||||
Effect of options and other dilutive securities | — | 4,570 | |||||||||
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents | $ | 346,340 | 210,710 | $ | 1.64 | ||||||
Year Ended December 31, 2011 | |||||||||||
Income | Shares | Per Share Amount | |||||||||
(Thousands, except per share amounts) | |||||||||||
Basic EPS from continuing operations | |||||||||||
Income from continuing operations attributable to ONEOK available for common stock | $ | 358,364 | 209,344 | $ | 1.71 | ||||||
Diluted EPS from continuing operations | |||||||||||
Effect of options and other dilutive securities | — | 5,154 | |||||||||
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents | $ | 358,364 | 214,498 | $ | 1.67 | ||||||
Year Ended December 31, 2010 | |||||||||||
Income | Shares | Per Share Amount | |||||||||
(Thousands, except per share amounts) | |||||||||||
Basic EPS from continuing operations | |||||||||||
Income from continuing operations attributable to ONEOK available for common stock | $ | 333,360 | 212,736 | $ | 1.57 | ||||||
Diluted EPS from continuing operations | |||||||||||
Effect of options and other dilutive securities | — | 2,834 | |||||||||
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents | $ | 333,360 | 215,570 | $ | 1.55 | ||||||
There were no option shares excluded from the calculation of diluted EPS for 2012, 2011 and 2010.
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L. SHARE-BASED PAYMENTS
The ONEOK, Inc. Equity Compensation Plan (the ECP) and the ONEOK, Inc. Long-Term Incentive Plan (the LTIP) provide for the granting of stock-based compensation, including incentive stock options, nonstatutory stock options, stock bonus awards, restricted stock awards, restricted stock-unit awards, performance stock awards and performance-unit awards to eligible employees and the granting of stock awards to nonemployee directors. We have reserved 10.0 million and 15.6 million shares of common stock for issuance under the ECP and LTIP, respectively. At December 31, 2012, we had approximately 3.4 million and 1.0 million shares available for issuance under the ECP and LTIP, respectively, which reflect shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under these plans, less forfeitures. These plans allow for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements.
Restricted Stock Units - We have granted restricted stock units to key employees that vest over a three-year period and entitle the grantee to receive shares of our common stock. Restricted stock unit awards are measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments and adjusted for estimated forfeitures. No dividends were paid prior to vesting on the restricted stock units granted prior to 2013. Beginning in 2013, restricted stock unit awards granted will accrue dividend equivalents prior to vesting. Compensation expense is recognized on a straight-line basis over the vesting period of the award.
Performance-Unit Awards - We have granted performance-unit awards to key employees. The shares of our common stock underlying the performance units vest at the expiration of a period determined by the Executive Compensation Committee if certain performance criteria are met by the company. Outstanding performance units vest at the expiration of a three-year period. Upon vesting, a holder of performance units is entitled to receive a number of shares of our common stock equal to a percentage (0 percent to 200 percent) of the performance units granted based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of other energy companies over the same period. Compensation expense is recognized on a straight-line basis over the period of the award.
If paid, the outstanding performance unit awards entitle the grantee to receive the grant in shares of our common stock. Our outstanding performance unit awards are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market condition is satisfied. The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. No dividends were paid prior to vesting on performance stock units granted prior to 2013. Beginning in 2013, performance stock unit awards granted will accrue dividend equivalents prior to vesting. The compensation expense on these awards only will be adjusted for changes in forfeitures.
Options - No stock options have been granted since 2003. Stock option activity was not material in 2012, 2011 and 2010. All previously issued stock options expired or have been exercised as of February 2013.
Stock Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) provides for the granting of stock options, stock bonus awards, including performance-unit awards, restricted stock awards and restricted stock unit awards. Under the DSCP, these awards may be granted by the Executive Compensation Committee at any time, until grants have been made for all shares authorized under the DSCP. We have reserved a total of 1.4 million shares of common stock for issuance under the DSCP, and at December 31, 2012, we had approximately 1.0 million shares available for issuance under the plan. The maximum number of shares of common stock that can be issued to a participant under the DSCP during any year is 40,000. No performance unit awards or restricted stock awards have been made to nonemployee directors under the DSCP.
General
For all awards outstanding, we used a forfeiture rate of 3 percent based on historical forfeitures under our share-based payment plans. We primarily use issuances from treasury stock to satisfy our share-based payment obligations.
Compensation cost expensed for our share-based payment plans described below was $22.6 million, $40.7 million and $15.9 million during 2012, 2011 and 2010, respectively, which is net of $14.2 million, $25.7 million and $10.0 million of tax benefits, respectively. Share-based compensation cost capitalized was not material for 2012 and 2011, and we had no share-based compensation cost capitalized for 2010.
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Cash received from the exercise of awards under all share-based payment arrangements was not material for 2012, 2011 and 2010. The tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements was not material for 2012, 2011 and 2010.
Restricted Stock Unit Activity
As of December 31, 2012, there was $11.4 million of total unrecognized compensation cost related to our nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 1.7 years. The following tables set forth activity and various statistics for our restricted stock unit awards:
Number of Shares | Weighted Average Price | ||||||
Nonvested December 31, 2011 | 1,368,674 | $ | 20.79 | ||||
Granted | 300,950 | $ | 36.65 | ||||
Released to participants | (589,333 | ) | $ | 17.13 | |||
Forfeited | (59,691 | ) | $ | 27.07 | |||
Nonvested December 31, 2012 | 1,020,600 | $ | 27.21 | ||||
2012 | 2011 | 2010 | ||||||||||
Weighted-average grant date fair value (per share) | $ | 36.65 | $ | 28.50 | $ | 18.67 | ||||||
Fair value of shares granted (thousands of dollars) | $ | 11,030 | $ | 11,728 | $ | 8,206 | ||||||
Performance-Unit Activity
As of December 31, 2012, there was $27.0 million of total unrecognized compensation cost related to the nonvested performance-unit awards, which is expected to be recognized over a weighted-average period of 1.7 years. The following tables set forth activity and various statistics related to the performance-unit awards and the assumptions used in the valuations of the 2012, 2011 and 2010 grants at the grant date:
Number of Units | Weighted Average Price | ||||||
Nonvested December 31, 2011 | 3,432,322 | $ | 23.68 | ||||
Granted | 600,750 | $ | 42.39 | ||||
Released to participants | (1,755,654 | ) | $ | 18.35 | |||
Forfeited | (144,261 | ) | $ | 32.49 | |||
Nonvested December 31, 2012 | 2,133,157 | $ | 32.74 | ||||
2012 | 2011 | 2010 | ||||
Volatility (a) | 27.00% | 39.91% | 40.60% | |||
Dividend Yield | 2.86% | 3.30% | 4.12% | |||
Risk-free Interest Rate | 0.38% | 1.33% | 1.47% | |||
(a) - Volatility was based on historical volatility over three years using daily stock price observations. | ||||||
2012 | 2011 | 2010 | ||||||||||
Weighted-average grant date fair value (per share) | $ | 42.39 | $ | 34.68 | $ | 24.05 | ||||||
Fair value of shares granted (thousands of dollars) | $ | 25,466 | $ | 29,186 | $ | 20,738 | ||||||
Employee Stock Purchase Plan
We have reserved a total of 11.6 million shares of common stock for issuance under our ONEOK, Inc. Employee Stock Purchase Plan (the ESPP). Subject to certain exclusions, all full-time employees are eligible to participate in the ESPP. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan. The Executive Compensation Committee may allow contributions to be made by other means, provided that in no event will contributions from all means exceed 10 percent of the employee’s annual base pay. The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price. Approximately 55 percent, 56 percent and 53 percent of employees participated in the plan in 2012, 2011 and 2010, respectively. Compensation expense
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for the ESPP was not material in 2012, and was $7.2 million and $3.9 million in 2011 and 2010, respectively. Under the plan, we sold 256,490 shares at $35.97 in 2012, 365,116 shares at $23.70 per share in 2011 and 433,794 shares at $18.98 per share in 2010.
Employee Stock Award Program
Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share. The total number of shares of our common stock available for issuance under this program was 900,000. Shares issued to employees under this program during 2012 and 2011 totaled 42,467 and 295,694, and compensation expense related to the Employee Stock Award Plan was not material in 2012 and $16.0 million in 2011. For 2010, the number of shares issued under this program and the related compensation expense were not material.
Deferred Compensation Plan for Non-Employee Directors
The ONEOK, Inc. Nonqualified Deferred Compensation Plan for Non-Employee Directors provides our directors, who are not our employees, the option to defer all or a portion of their compensation for their service on our Board of Directors. Under the plan, directors may elect either a cash deferral option or a phantom stock option. Under the cash deferral option, directors may defer the receipt of all or a portion of their annual retainer fees, plus accrued interest. Under the phantom stock option, directors may defer all or a portion of their annual retainer fees and receive such fees on a deferred basis in the form of shares of common stock under our Long-Term Incentive Plan or Equity Compensation Plan. Shares are distributed to nonemployee directors at the fair market value of our common stock at the date of distribution.
M. EMPLOYEE BENEFIT PLANS
Retirement and Postretirement Benefit Plans
Retirement Plans - We have a defined benefit pension plan covering nonbargaining unit employees hired before January 1, 2005, and certain bargaining-unit employees hired before December 15, 2011. Nonbargaining unit employees hired after December 31, 2004, employees represented by Local No. 304 of the IBEW hired on or after July 1, 2010, employees represented by the United Steelworkers hired on or after December 15, 2011, and employees who accepted a one-time opportunity to opt out of our pension plan, are covered by a profit sharing plan. In addition, we have a supplemental executive retirement plan for the benefit of certain officers. No new participants in our supplemental executive retirement plan have been approved since 2005. We fund our pension costs at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended, and the Pension Protection Act of 2006.
Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service. The postretirement medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance.
In December 2011, we announced to participants a change from a self-insured postretirement medical plan to a fully insured solution for plan participants who are medicare eligible. This announcement resulted in a $44.6 million reduction in our accumulated postretirement benefit obligation that was recognized in other comprehensive income and will be amortized to net periodic benefit cost over the expected remaining years of service for plan participants.
Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and postretirement benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for pension and postretirement costs. Differences, if any, between the expense and the amount recovered through rates are reflected in earnings, net of authorized deferrals.
Our regulated entities historically have recovered pension and postretirement benefit costs through rates. We believe it is probable that regulators will continue to include the net periodic pension and postretirement benefit costs in our regulated entities’ cost of service. Accordingly, we have recorded a regulatory asset for the minimum liability associated with our regulated entities’ pension and postretirement benefit obligations that otherwise would have been recorded in accumulated other comprehensive income.
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Obligations and Funded Status - The following tables set forth our pension and postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated:
Pension Benefits December 31, | Postretirement Benefits December 31, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Change in Benefit Obligation | (Thousands of dollars) | |||||||||||||||
Benefit obligation, beginning of period | $ | 1,215,932 | $ | 1,098,232 | $ | 286,044 | $ | 295,483 | ||||||||
Service cost | 21,301 | 20,013 | 4,960 | 4,987 | ||||||||||||
Interest cost | 59,237 | 58,757 | 13,893 | 15,632 | ||||||||||||
Plan participants’ contributions | — | — | 5,851 | 6,751 | ||||||||||||
Actuarial loss | 105,732 | 92,609 | 9,935 | 25,617 | ||||||||||||
Benefits paid | (88,642 | ) | (53,679 | ) | (21,380 | ) | (17,864 | ) | ||||||||
Plan amendment | — | — | (131 | ) | (44,562 | ) | ||||||||||
Benefit obligation, end of period | 1,313,560 | 1,215,932 | 299,172 | 286,044 | ||||||||||||
Change in Plan Assets | ||||||||||||||||
Fair value of plan assets, beginning of period | 902,235 | 904,089 | 124,163 | 117,585 | ||||||||||||
Actual return on plan assets | 90,026 | (10,750 | ) | 14,273 | (4,876 | ) | ||||||||||
Employer contributions | 91,881 | 62,575 | 10,728 | 11,454 | ||||||||||||
Benefits paid | (88,878 | ) | (53,679 | ) | (1,002 | ) | — | |||||||||
Fair value of assets, end of period | 995,264 | 902,235 | 148,162 | 124,163 | ||||||||||||
Balance at December 31 | $ | (318,296 | ) | $ | (313,697 | ) | $ | (151,010 | ) | $ | (161,881 | ) | ||||
Current liabilities | $ | (4,695 | ) | $ | (4,545 | ) | $ | — | $ | — | ||||||
Noncurrent liabilities | (313,601 | ) | (309,152 | ) | (151,010 | ) | (161,881 | ) | ||||||||
Balance at December 31 | $ | (318,296 | ) | $ | (313,697 | ) | $ | (151,010 | ) | $ | (161,881 | ) | ||||
The accumulated benefit obligation for our pension plans was $1,240.3 million and $1,152.4 million at December 31, 2012 and 2011, respectively.
There are no plan assets expected to be withdrawn and returned to us in 2013.
Components of Net Periodic Benefit Cost - The following tables set forth the components of net periodic benefit cost for our pension and postretirement benefit plans for the periods indicated:
Pension Benefits Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Components of net periodic benefit cost | ||||||||||||
Service cost | $ | 21,301 | $ | 20,013 | $ | 19,277 | ||||||
Interest cost | 59,237 | 58,757 | 58,143 | |||||||||
Expected return on assets | (82,756 | ) | (75,500 | ) | (73,651 | ) | ||||||
Amortization of unrecognized prior service cost | 969 | 1,018 | 1,278 | |||||||||
Amortization of net loss | 48,439 | 35,708 | 27,555 | |||||||||
Settlements | 1,401 | — | — | |||||||||
Net periodic benefit cost | $ | 48,591 | $ | 39,996 | $ | 32,602 | ||||||
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Postretirement Benefits Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Components of net periodic benefit cost | ||||||||||||
Service cost | $ | 4,960 | $ | 4,987 | $ | 4,926 | ||||||
Interest cost | 13,893 | 15,632 | 15,643 | |||||||||
Expected return on assets | (10,687 | ) | (10,272 | ) | (7,896 | ) | ||||||
Amortization of unrecognized net asset at adoption | 2,874 | 3,189 | 3,189 | |||||||||
Amortization of unrecognized prior service cost | (8,252 | ) | (2,518 | ) | (2,003 | ) | ||||||
Amortization of net loss | 13,184 | 8,123 | 7,009 | |||||||||
Net periodic benefit cost | $ | 15,972 | $ | 19,141 | $ | 20,868 | ||||||
Other Comprehensive Income (Loss) - The following tables set forth the amounts recognized in other comprehensive income (loss) related to our pension benefits and postretirement benefits for the periods indicated:
Pension Benefits Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Regulatory asset gain | $ | 67,472 | $ | 114,625 | $ | 19,146 | ||||||
Net loss arising during the period | (103,199 | ) | (182,987 | ) | (43,055 | ) | ||||||
Amortization of regulatory asset | (32,527 | ) | (23,265 | ) | (18,359 | ) | ||||||
Amortization of prior service credit | 969 | 1,018 | 1,278 | |||||||||
Amortization of loss | 49,839 | 35,708 | 27,555 | |||||||||
Deferred income taxes | 6,748 | 21,236 | 5,197 | |||||||||
Total recognized in other comprehensive income (loss) | $ | (10,698 | ) | $ | (33,665 | ) | $ | (8,238 | ) | |||
Postretirement Benefits Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Regulatory asset gain | $ | 4,376 | $ | 7,389 | $ | 8,408 | ||||||
Net loss arising during the period | (6,348 | ) | (40,765 | ) | (15,980 | ) | ||||||
Amortization of regulatory asset | (6,557 | ) | (7,214 | ) | (6,759 | ) | ||||||
Amortization of transition obligation | 2,874 | 3,189 | 3,189 | |||||||||
Amortization of prior service cost | (8,252 | ) | (2,518 | ) | (2,003 | ) | ||||||
Amortization of loss | 13,184 | 8,123 | 7,009 | |||||||||
Plan amendment | 131 | 44,562 | — | |||||||||
Deferred income taxes | 229 | (4,938 | ) | 2,373 | ||||||||
Total recognized in other comprehensive income (loss) | $ | (363 | ) | $ | 7,828 | $ | (3,763 | ) | ||||
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The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense for the periods indicated:
Pension Benefits December 31, | Postretirement Benefits December 31, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(Thousands of dollars) | ||||||||||||||||
Transition obligation | $ | — | $ | — | $ | (283 | ) | $ | (3,157 | ) | ||||||
Prior service credit (cost) | (2,022 | ) | (2,991 | ) | 38,301 | 46,426 | ||||||||||
Accumulated loss | (684,245 | ) | (630,886 | ) | (116,652 | ) | (123,489 | ) | ||||||||
Accumulated other comprehensive loss before regulatory assets | (686,267 | ) | (633,877 | ) | (78,634 | ) | (80,220 | ) | ||||||||
Regulatory asset for regulated entities | 442,833 | 407,886 | 56,571 | 58,752 | ||||||||||||
Accumulated other comprehensive loss after regulatory assets | (243,434 | ) | (225,991 | ) | (22,063 | ) | (21,468 | ) | ||||||||
Deferred income taxes | 94,161 | 87,413 | 8,534 | 8,305 | ||||||||||||
Accumulated other comprehensive loss, net of tax | $ | (149,273 | ) | $ | (138,578 | ) | $ | (13,529 | ) | $ | (13,163 | ) | ||||
The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year:
Pension Benefits | Postretirement Benefits | |||||||
Amounts to be recognized in 2013 | (Thousands of dollars) | |||||||
Transition obligation | $ | — | $ | 284 | ||||
Prior service credit (cost) | $ | 920 | $ | (6,671 | ) | |||
Net loss | $ | 66,282 | $ | 12,629 | ||||
Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for pension and postretirement benefits for the periods indicated:
Pension Benefits | Postretirement Benefits | ||||||
Years Ended December 31, | |||||||
2012 | 2011 | 2012 | 2011 | ||||
Discount rate | 4.25% | 5.00% | 4.00% | 5.00% | |||
Compensation increase rate | 3.45% - 3.50% | 3.2% - 3.8% | 3.45% - 3.50% | 3.2% - 3.8% | |||
The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated:
Years Ended December 31, | ||||||
2012 | 2011 | 2010 | ||||
Discount rate | 5.00% | 5.50% | 6.00% | |||
Expected long-term return on plan assets | 8.25% | 8.25% | 8.50% | |||
Compensation increase rate | 3.20% - 3.80% | 3.30% - 3.90% | 3.1% - 4.0% | |||
We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models.
We determine our discount rates annually. We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our pension and postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows. Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds. Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.
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Health Care Cost Trend Rates - The following table sets forth the assumed health care cost-trend rates for the periods indicated:
2012 | 2011 | |||
Health care cost-trend rate assumed for next year | 4.0% - 9.0% | 4.0% - 9.0% | ||
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate) | 4.0% - 5.0% | 4.0% - 5.0% | ||
Year that the rate reaches the ultimate trend rate | 2022 | 2021 | ||
Assumed health care cost-trend rates have a significant effect on the amounts reported for our health care plans. A one percentage point change in assumed health care cost-trend rates would have the following effects:
One Percentage Point Increase | One Percentage Point Decrease | |||||||
(Thousands of dollars) | ||||||||
Effect on total of service and interest cost | $ | 1,420 | $ | (1,261 | ) | |||
Effect on postretirement benefit obligation | $ | 17,518 | $ | (16,125 | ) | |||
Plan Assets - Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals. The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations. The plan’s investments include a diverse blend of various domestic and international equities, investments in various classes of debt securities, insurance contracts and venture capital. The target allocation for the assets of our pension plan is as follows:
U.S. large-cap equities | 37 | % | |
Aggregate bonds | 24 | % | |
Developed foreign large-cap equities | 10 | % | |
Alternative investments | 8 | % | |
Mid-cap equities | 6 | % | |
Emerging markets equities | 5 | % | |
Small-cap equities | 4 | % | |
High yield bonds | 3 | % | |
Developed foreign bonds | 2 | % | |
Emerging market bonds | 1 | % | |
Total | 100 | % | |
As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.
The following tables set forth our pension benefits and postretirement benefits plan assets by fair value category as of the measurement date:
Pension Benefits | ||||||||||||||||
December 31, 2012 | ||||||||||||||||
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Thousands of dollars) | ||||||||||||||||
Investments: | ||||||||||||||||
Equity securities (a) | $ | 541,539 | $ | 61,242 | $ | — | $ | 602,781 | ||||||||
Government obligations | — | 116,936 | — | 116,936 | ||||||||||||
Corporate obligations (b) | — | 104,078 | — | 104,078 | ||||||||||||
Cash and money market funds (c) | 33,296 | — | — | 33,296 | ||||||||||||
Insurance contracts and group annuity contracts | — | — | 70,411 | 70,411 | ||||||||||||
Other investments (d) | — | — | 67,762 | 67,762 | ||||||||||||
Total assets | $ | 574,835 | $ | 282,256 | $ | 138,173 | $ | 995,264 | ||||||||
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments.
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Pension Benefits | ||||||||||||||||
December 31, 2011 | ||||||||||||||||
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Thousands of dollars) | ||||||||||||||||
Investments: | ||||||||||||||||
Equity securities (a) | $ | 481,971 | $ | 32,475 | $ | — | $ | 514,446 | ||||||||
Government obligations | — | 96,341 | — | 96,341 | ||||||||||||
Corporate obligations (b) | 18,835 | 58,977 | — | 77,812 | ||||||||||||
Cash and money market funds (c) | 76,575 | — | — | 76,575 | ||||||||||||
Insurance contracts and group annuity contracts | — | — | 70,818 | 70,818 | ||||||||||||
Other investments (d) | — | — | 66,243 | 66,243 | ||||||||||||
Total assets | $ | 577,381 | $ | 187,793 | $ | 137,061 | $ | 902,235 | ||||||||
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
(d) - This category represents alternative investments.
Postretirement Benefits | ||||||||||||||||
December 31, 2012 | ||||||||||||||||
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Thousands of dollars) | ||||||||||||||||
Investments: | ||||||||||||||||
Equity securities (a) | $ | 21,548 | $ | 140 | $ | — | $ | 21,688 | ||||||||
Government obligations | — | 268 | — | 268 | ||||||||||||
Corporate obligations (b) | 17,522 | 238 | — | 17,760 | ||||||||||||
Cash and money market funds (c) | 18,311 | — | — | 18,311 | ||||||||||||
Insurance contracts and group annuity contracts | — | 89,979 | — | 89,979 | ||||||||||||
Other investments | — | — | 156 | 156 | ||||||||||||
Total assets | $ | 57,381 | $ | 90,625 | $ | 156 | $ | 148,162 | ||||||||
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category is primarily money market funds.
Postretirement Benefits | ||||||||||||||||
December 31, 2011 | ||||||||||||||||
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(Thousands of dollars) | ||||||||||||||||
Investments: | ||||||||||||||||
Equity securities (a) | $ | 21,915 | $ | 113 | $ | — | $ | 22,028 | ||||||||
Government obligations | — | 334 | — | 334 | ||||||||||||
Corporate obligations (b) | 12,156 | 205 | — | 12,361 | ||||||||||||
Cash and money market funds (c) | 12,477 | — | — | 12,477 | ||||||||||||
Insurance contracts and group annuity contracts | — | 76,733 | — | 76,733 | ||||||||||||
Other investments | — | — | 230 | 230 | ||||||||||||
Total assets | $ | 46,548 | $ | 77,385 | $ | 230 | $ | 124,163 | ||||||||
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds from diverse industries.
(c) - This category represents money market funds.
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The following tables set forth the reconciliation of Level 3 fair value measurements of our pension plan for the periods indicated:
Pension Benefits | ||||||||||||
December 31, 2012 | ||||||||||||
Insurance Contracts | Other Investments | Total | ||||||||||
(Thousands of dollars) | ||||||||||||
January 1, 2012 | $ | 70,818 | $ | 66,243 | $ | 137,061 | ||||||
Net realized and unrealized gains (losses) | (407 | ) | 1,519 | 1,112 | ||||||||
December 31, 2012 | $ | 70,411 | $ | 67,762 | $ | 138,173 | ||||||
Pension Benefits | ||||||||||||
December 31, 2011 | ||||||||||||
Insurance Contracts | Other Investments | Total | ||||||||||
(Thousands of dollars) | ||||||||||||
January 1, 2011 | $ | 72,198 | $ | 1,062 | $ | 73,260 | ||||||
Purchases | — | 65,000 | 65,000 | |||||||||
Net realized and unrealized gains (losses) | (1,380 | ) | 181 | (1,199 | ) | |||||||
December 31, 2011 | $ | 70,818 | $ | 66,243 | $ | 137,061 | ||||||
Contributions - During 2012, we made contributions of $91.9 million and $10.7 million to our defined benefit pension plans and postretirement benefit plans, respectively. The contributions to our defined benefit pension plans were attributable to the 2013 plan year. In 2013, we expect to contribute $4.8 million and $11.8 million to our defined benefit pension and postretirement plans, respectively.
Pension and Postretirement Benefit Payments - Benefit payments for our pension and postretirement benefit plans for the period ending December 31, 2012, were $88.6 million and $21.4 million, respectively. The following table sets forth the pension benefits and postretirement benefits payments expected to be paid in 2013-2022:
Pension Benefits | Postretirement Benefits | |||||||
Benefits to be paid in: | (Thousands of dollars) | |||||||
2013 | $ | 64,821 | $ | 16,253 | ||||
2014 | $ | 66,831 | $ | 16,954 | ||||
2015 | $ | 68,617 | $ | 17,762 | ||||
2016 | $ | 70,724 | $ | 18,653 | ||||
2017 | $ | 73,104 | $ | 19,832 | ||||
2018 through 2022 | $ | 404,947 | $ | 112,059 | ||||
The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2012, and include estimated future employee service.
Other Employee Benefit Plans
Thrift Plan - We have a Thrift Plan covering all full-time employees, and employee contributions are discretionary. We match 100 percent of employee contributions up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our contributions made to the plan were $16.4 million, $15.9 million and $15.4 million in 2012, 2011 and 2010, respectively.
Profit Sharing Plan - We have a profit sharing plan for all nonbargaining unit employees hired after December 31, 2004, and employees covered by the IBEW collective bargaining agreement hired after June 30, 2010. Nonbargaining unit employees who were employed prior to January 1, 2005, and employees covered by the IBEW collective bargaining agreement employed prior to July 1, 2010, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan and not accrue any additional benefits under our defined benefit pension plan after December 31, 2004, and June 30, 2010, respectively. Employees covered by the United Steelworker collective bargaining agreement employed prior to December 16, 2011, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan. We plan to
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make a contribution to the profit sharing plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan. Our contributions made to the plan were $6.6 million, $6.7 million and $4.7 million in 2012, 2011 and 2010, respectively.
Employee Deferred Compensation Plan - The ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Our contributions made to the plan were not material in 2012, 2011 and 2010.
N. INCOME TAXES
The following table sets forth our provisions for income taxes for the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Current income taxes | (Thousands of dollars) | |||||||||||
Federal | $ | (16,083 | ) | $ | (32,291 | ) | $ | 58,844 | ||||
State | 1,798 | 1,707 | 12,629 | |||||||||
Total current income taxes from continuing operations | (14,285 | ) | (30,584 | ) | (a) | 71,473 | ||||||
Deferred income taxes | ||||||||||||
Federal | 213,127 | 228,257 | 124,126 | |||||||||
State | 16,353 | 28,375 | 18,121 | |||||||||
Total deferred income taxes from continuing operations | 229,480 | 256,632 | (a) | 142,247 | ||||||||
Total provision for income taxes from continuing operations | 215,195 | 226,048 | 213,720 | |||||||||
Discontinued operations | 8,749 | 1,255 | 114 | |||||||||
Total provision for income taxes | $ | 223,944 | $ | 227,303 | $ | 213,834 | ||||||
(a) Includes a $37.7 million reclassification from current income taxes to deferred related to revisions of estimated depreciation in our filed tax returns compared with our 2010 tax provision.
The following table is a reconciliation of our income tax provision from continuing operations for the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Income from continuing operations before income taxes | $ | 944,446 | $ | 983,562 | $ | 753,778 | ||||||
Less: Net income attributable to noncontrolling interest | 382,911 | 399,150 | 206,698 | |||||||||
Income from continuing operations attributable to ONEOK before income taxes | 561,535 | 584,412 | 547,080 | |||||||||
Federal statutory income tax rate | 35 | % | 35 | % | 35 | % | ||||||
Provision for federal income taxes | 196,537 | 204,543 | 191,478 | |||||||||
State income taxes, net of federal tax benefit | 11,799 | 20,334 | 19,946 | |||||||||
Other, net | 6,859 | 1,171 | 2,296 | |||||||||
Income tax provision from continuing operations | $ | 215,195 | $ | 226,048 | $ | 213,720 | ||||||
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The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated:
December 31, 2012 | December 31, 2011 | |||||||
Deferred tax assets | (Thousands of dollars) | |||||||
Employee benefits and other accrued liabilities | $ | 128,418 | $ | 136,997 | ||||
Other comprehensive income | 140,802 | 134,037 | ||||||
Other | 33,436 | 31,544 | ||||||
Total deferred tax assets | 302,656 | 302,578 | ||||||
Deferred tax liabilities | ||||||||
Excess of tax over book depreciation and depletion | 760,211 | 664,415 | ||||||
Investment in partnerships | 969,347 | 851,408 | ||||||
Regulatory assets | 204,625 | 200,010 | ||||||
Total deferred tax liabilities | 1,934,183 | 1,715,833 | ||||||
Net deferred tax liabilities before discontinued operations | 1,631,527 | 1,413,255 | ||||||
Discontinued operations | — | 82 | ||||||
Net deferred tax liabilities | $ | 1,631,527 | $ | 1,413,337 | ||||
We had income taxes receivable of approximately $30.8 million and $10.7 million at December 31, 2012 and 2011, respectively.
O. UNCONSOLIDATED AFFILIATES
Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated:
Net Ownership Interest | December 31, 2012 | December 31, 2011 | ||||||||
(Thousands of dollars) | ||||||||||
Northern Border Pipeline | 50% | $ | 393,317 | $ | 416,206 | |||||
Overland Pass Pipeline Company | 50% | 468,710 | 447,449 | |||||||
Fort Union Gas Gathering, L.L.C. | 37% | 120,782 | 117,353 | |||||||
Bighorn Gas Gathering, L.L.C. | 49% | 90,428 | 91,748 | |||||||
Other | Various | 148,168 | 150,642 | |||||||
Investments in unconsolidated affiliates (a) | $ | 1,221,405 | $ | 1,223,398 | ||||||
(a) - Equity method goodwill (Note A) was $224.3 million at December 31, 2012 and 2011.
Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Northern Border Pipeline | $ | 72,705 | $ | 76,365 | $ | 68,124 | ||||||
Overland Pass Pipeline Company (a) | 20,043 | 19,535 | 5,421 | |||||||||
Fort Union Gas Gathering, L.L.C. | 17,218 | 15,280 | 14,367 | |||||||||
Bighorn Gas Gathering, L.L.C. | 3,820 | 5,990 | 5,495 | |||||||||
Other | 9,238 | 10,076 | 8,473 | |||||||||
Equity earnings from investments | $ | 123,024 | $ | 127,246 | $ | 101,880 | ||||||
(a) - Beginning in September 2010, following the sale of a 49-percent interest, Overland Pass Pipeline Company was deconsolidated and prospectively accounted for under the equity method.
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Unconsolidated Affiliates Financial Information - The following tables set forth summarized combined financial information of our unconsolidated affiliates for the periods indicated:
December 31, 2012 | December 31, 2011 | |||||||
(Thousands of dollars) | ||||||||
Balance Sheet | ||||||||
Current assets | $ | 175,930 | $ | 133,579 | ||||
Property, plant and equipment, net | $ | 2,593,122 | $ | 2,451,798 | ||||
Other noncurrent assets | $ | 35,005 | $ | 35,548 | ||||
Current liabilities | $ | 145,147 | $ | 76,355 | ||||
Long-term debt | $ | 472,630 | $ | 534,485 | ||||
Other noncurrent liabilities | $ | 42,451 | $ | 15,510 | ||||
Accumulated other comprehensive loss | $ | (2,503 | ) | $ | (2,700 | ) | ||
Owners’ equity | $ | 2,146,332 | $ | 1,997,275 | ||||
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Income Statement (a) | ||||||||||||
Operating revenues | $ | 573,197 | $ | 496,158 | $ | 440,826 | ||||||
Costs and expenses | $ | 269,858 | $ | 221,261 | $ | 189,437 | ||||||
Net income | $ | 279,766 | $ | 249,559 | $ | 223,715 | ||||||
Distributions paid to us (a) | $ | 155,741 | $ | 156,385 | $ | 114,805 | ||||||
(a) - Financial information for 2012 and 2011 is not directly comparable with 2010 due to the deconsolidation of Overland Pass Pipeline Company in September 2010. | ||||||||||||
We incurred expenses in transactions with unconsolidated affiliates of $36.5 million, $33.7 million, and $15.9 million for 2012, 2011, and 2010, respectively, primarily related to Overland Pass Pipeline Company. Accounts payable to our equity method investees at December 31, 2012 and 2011, were not material.
Overland Pass Pipeline Company - In September 2010, ONEOK Partners completed a transaction to sell a 49-percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams Partners, resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, ONEOK Partners received approximately $423.7 million in cash at closing. As a result of the transaction, ONEOK Partners no longer controls Overland Pass Pipeline Company and began accounting for the investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, ONEOK Partners recognized approximately $16.3 million in gain on sale of assets, primarily attributable to the remeasurement of its retained investment in Overland Pass Pipeline Company to its fair value, and has recorded its retained investment of approximately $438.0 million in investments in unconsolidated affiliates. The estimate of the fair value of ONEOK Partners’ retained interest in Overland Pass Pipeline Company was based upon the income and market valuation approaches.
The Overland Pass Pipeline Company limited liability company agreement provides that distributions to Overland Pass Pipeline Company’s members are to be made on a pro-rata basis according to each member’s percentage interest. The Overland Pass Pipeline Company Management Committee determines the amount and timing of such distributions. Any changes to, or suspensions of, cash distributions from Overland Pass Pipeline Company requires the unanimous approval of the Overland Pass Pipeline Management Committee. Cash distributions are equal to 100 percent of available cash as defined in the limited liability company agreement.
Northern Border Pipeline - The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro-rata basis according to each partner’s percentage interest. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. Cash distributions are equal to 100 percent of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon EBITDA less interest expense and maintenance capital expenditures. Loans or other advances from Northern Border Pipeline to its partners or affiliates are prohibited under its credit
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agreement. The Northern Border Pipeline Management Committee has adopted a cash distribution policy related to financial ratio targets and capital contributions. The cash distribution policy defines minimum equity-to- total-capitalization ratios to be used by the Northern Border Pipeline Management Committee to establish the timing and amount of required capital contributions. In addition, any shortfall due to the inability to refinance maturing debt will be funded by capital contributions.
In September 2012, Northern Border Pipeline Company filed with the FERC a settlement with its customers to modify its transportation rates. In January 2013, the settlement was approved and the new rates are effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower compared with previous rates and are expected to reduce ONEOK Partners’ future equity earnings and cash distributions from Northern Border Pipeline.
P. ONEOK PARTNERS
Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of December 31, 2012:
General partner interest | 2.0 | % |
Limited partner interest (a) | 41.4 | % |
Total ownership interest | 43.4 | % |
(a) - Represents 19.8 million common units and approximately 73.0 million Class B units, which are convertible, at our option, into common units. | ||
In January 2013, ONEOK Partners entered into the EDA for the offer and sale from time to time of its common units up to an aggregate amount of $300 million. The EDA allows ONEOK Partners to offer and sell its common units representing limited partner interests at prices ONEOK Partners deems appropriate for its common units through a sales agent. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between ONEOK Partners and the sales agent. ONEOK Partners is under no obligation to offer common units under the EDA. ONEOK Partners intends to use the net proceeds from sales under the program for general partnership purposes.
In March 2012, ONEOK Partners completed an underwritten public offering of 8.0 million common units at a public offering price of $59.27 per common unit, generating net proceeds of approximately $460 million. ONEOK Partners also sold 8.0 million common units to us in a private placement, generating net proceeds of approximately $460 million. In conjunction with the issuances, ONEOK Partners GP contributed approximately $19 million in order to maintain its 2-percent general partner interest in ONEOK Partners. ONEOK Partners used the net proceeds from the issuances to repay $295 million of borrowings under its commercial paper program, to repay amounts on the maturity of its $350 million, 5.9-percent senior notes due April 2012 and for other general partnership purposes, including capital expenditures. As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent from 42.8 percent.
In July 2011, ONEOK Partners completed a two-for-one split of ONEOK Partners’ common and Class B units and amended its Partnership Agreement to adjust the formula for distributing available cash among us and limited partners to reflect the unit split.
In February 2010, ONEOK Partners completed an underwritten public offering of 11,001,800 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $30.38 per common unit, generating net proceeds of approximately $322.7 million. In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2-percent general partner interest. ONEOK Partners used the proceeds from the sale of the common units and the general partner contribution to repay borrowings under its previous credit agreement and for general partnership purposes.
We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction. If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital. As a result of ONEOK Partners’ issuance of common units, we recognized a decrease to paid-in capital of approximately $51.1 million in 2012 and an increase to paid-in capital of $50.7 million in 2010.
Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2-percent general partner interest, which includes our incentive distribution rights. Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in ONEOK Partners’ partnership agreement, as amended. Available cash generally will be distributed
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98 percent to limited partners and 2 percent to the general partner. The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. In July 2011, the partnership agreement was amended to adjust the formula for distributing available cash among the general partner and limited partners to reflect the two-for-one unit split. Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the general partner receives:
• | 15 percent of amounts distributed in excess of $0.3025 per unit; |
• | 25 percent of amounts distributed in excess of $0.3575 per unit; and |
• | 50 percent of amounts distributed in excess of $0.4675 per unit. |
The following table shows ONEOK Partners’ distributions paid during the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands, except per unit amounts) | ||||||||||||
Distribution per unit | $ | 2.590 | $ | 2.325 | $ | 2.230 | ||||||
General partner distributions | $ | 15,217 | $ | 12,189 | $ | 11,265 | ||||||
Incentive distributions | 186,130 | 123,386 | 103,463 | |||||||||
Distributions to general partner | 201,347 | 135,575 | 114,728 | |||||||||
Limited partner distributions to ONEOK | 235,442 | 197,132 | 189,076 | |||||||||
Limited partner distributions to noncontrolling interest | 324,123 | 276,739 | 259,380 | |||||||||
Total distributions paid | $ | 760,912 | $ | 609,446 | $ | 563,184 | ||||||
ONEOK Partners’ distributions are declared and paid within 45 days of the end of each quarter. The following table shows ONEOK Partners’ distributions declared for the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands, except per unit amounts) | ||||||||||||
Distribution per unit | $ | 2.690 | $ | 2.365 | $ | 2.250 | ||||||
General partner distributions | $ | 16,355 | $ | 12,515 | $ | 11,577 | ||||||
Incentive distributions | 210,095 | 131,212 | 108,711 | |||||||||
Distributions to general partner | 226,450 | 143,727 | 120,288 | |||||||||
Limited partner distributions to ONEOK | 249,600 | 200,524 | 190,774 | |||||||||
Limited partner distributions to noncontrolling interest | 341,704 | 281,500 | 267,812 | |||||||||
Total distributions declared | $ | 817,754 | $ | 625,751 | $ | 578,874 | ||||||
Relationship - We consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for the distributions we receive. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement. See Note R for more information on ONEOK Partners’ results.
Affiliate Transactions - We have certain transactions with ONEOK Partners and its subsidiaries, which collectively comprise our ONEOK Partners segment.
ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment. In addition, a portion of ONEOK Partners’ revenues from its natural gas pipelines business is from our Energy Services and Natural Gas Distribution segments, which contract with ONEOK Partners for natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and its natural gas gathering and processing operations.
Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which it contracted for all of OBPI’s rights, including all of the capacity of the Bushton Plant, reimbursing OBPI for all costs associated with the operation and maintenance of the Bushton Plant and its obligations under equipment leases covering portions of the Bushton Plant. In June 2011, through a series of transactions, we sold OBPI to ONEOK Partners and OBPI closed the purchase option and
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terminated the equipment leases. The total amount paid by ONEOK Partners to complete the transactions was approximately $94.2 million, which included the reimbursement to us of obligations related to the Processing and Services Agreement.
We provide a variety of services to our affiliates, including cash management and financial services, legal and administrative services by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are incurred specifically on behalf of an affiliate, the costs are billed directly to the affiliate by us. In other situations, the costs may be allocated to the affiliates through a variety of methods, depending upon the nature of the expenses and the activities of the affiliates. For example, a service that applies equally to all employees is allocated based upon the number of employees in each affiliate. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, operating income and payroll expense. It is not practicable to determine what these general overhead costs would be on a stand-alone basis.
The following table shows ONEOK Partners’ transactions with us for the periods indicated:
Years Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(Thousands of dollars) | ||||||||||||
Revenues | $ | 352,099 | $ | 403,603 | $ | 457,740 | ||||||
Expenses | ||||||||||||
Cost of sales and fuel | $ | 33,094 | $ | 48,163 | $ | 53,107 | ||||||
Administrative and general expenses | 246,050 | 251,239 | 207,282 | |||||||||
Total expenses | $ | 279,144 | $ | 299,402 | $ | 260,389 | ||||||
Q. COMMITMENTS AND CONTINGENCIES
Commitments - Operating leases represent future minimum lease payments under noncancelable equipment leases covering office space, pipeline equipment, rights of way and vehicles. Firm transportation and storage contracts are fixed-price contracts that provide us with firm transportation and storage capacity. Rental expense in 2012, 2011 and 2010 was not material. The following table sets forth our operating lease and firm transportation and storage contract payments for the periods indicated:
ONEOK | Operating Leases | Firm Transportation and Storage Contracts | Total | |||||||||
(Millions of dollars) | ||||||||||||
2013 | $ | 1.2 | $ | 130.3 | $ | 131.5 | ||||||
2014 | 1.0 | 99.1 | 100.1 | |||||||||
2015 | 0.6 | 53.5 | 54.1 | |||||||||
2016 | 0.2 | 27.6 | 27.8 | |||||||||
2017 | — | 15.0 | 15.0 | |||||||||
Thereafter | — | 9.4 | 9.4 | |||||||||
Total | $ | 3.0 | $ | 334.9 | $ | 337.9 | ||||||
ONEOK Partners | Operating Leases | Firm Transportation and Storage Contracts | Total | |||||||||
(Millions of dollars) | ||||||||||||
2013 | $ | 0.6 | $ | 16.3 | $ | 16.9 | ||||||
2014 | 1.8 | 13.2 | 15.0 | |||||||||
2015 | 0.4 | 13.0 | 13.4 | |||||||||
2016 | 0.3 | 11.7 | 12.0 | |||||||||
2017 | 0.2 | 10.1 | 10.3 | |||||||||
Thereafter | 0.3 | 42.3 | 42.6 | |||||||||
Total | $ | 3.6 | $ | 106.6 | $ | 110.2 | ||||||
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Environmental Matters - We are subject to multiple historical, wildlife preservation and environmental laws and regulations, which affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands preservation, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows. In addition, emission controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We own or retain legal responsibility for the environmental conditions at 12 former manufactured natural gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater.
Of the 12 sites, we have begun soil remediation on 11 sites. Regulatory closure has been achieved at three locations, and we have completed or are near completion of soil remediation at eight sites. We have begun site assessment at the remaining site where no active remediation has occurred.
Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters had no material effects on earnings or cash flows during 2012, 2011 or 2010.
In May 2010, the EPA finalized the “Tailoring Rule” that regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and at current emission threshold levels has not had a material impact on our existing facilities. The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.
In 2010, the EPA issued the RICE NESHAP, which initially included a compliance date in 2013. Subsequent industry appeals and settlements with the EPA have extended timelines associated with the final RICE NESHAP rule. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.
In July 2011, the EPA issued a proposed rule that would change the air emission New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and gas industry, including natural gas production, processing, transmission and underground storage. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification. Further, pursuant to various industry comments, administrative petitions for reconsideration and/or judicial appeals of portions of the NSPS final rule, the EPA has indicated it may provide certain responses, amendments and/or policy guidance to amend or clarify portions of the final rule in 2013. We anticipate that if EPA issues additional responses, amendments and/or policy guidance on the final rule, it will reduce the anticipated capital, operations and maintenance costs resulting from the regulation. Generally, the NSPS final rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.
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Pipeline Safety - We are subject to PHMSA regulations, including integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The new law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include but are not limited to the following:
• | an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas; |
• | a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions; |
• | a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and |
• | a requirement to test previously untested pipelines operating above 30-percent yield strength in high-consequence areas. |
The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.
Financial Markets Legislation - The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act. The CFTC has issued final regulations for many provisions of the Dodd-Frank Act that have varying effective dates for compliance, but others remain outstanding. Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the capital requirements and costs of hedging may increase as a result of the regulations. We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material. These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future. Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, and we are unable to estimate reasonably possible losses, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
R. SEGMENTS
Segment Descriptions - Our operations are divided into three reportable business segments as follows: (i) our ONEOK Partners segment reflects the consolidated operations of ONEOK Partners. We own a 43.4-percent ownership interest and control ONEOK Partners through our ownership of its general partner interest. ONEOK Partners gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs. We and ONEOK Partners maintain significant financial and corporate governance separations. We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of its businesses individually; (ii) our Natural Gas Distribution segment is comprised of our regulated public utilities that deliver natural gas to residential, commercial and industrial customers, and transport natural gas; and (iii) our Energy Services segment markets natural gas to wholesale customers. Other and eliminations consist of the operating and leasing operations of our headquarters building and related parking facility and other amounts needed to reconcile our reportable segments to our consolidated financial statements.
Accounting Policies - We evaluate performance based principally on each segment’s operating income and equity earnings. The accounting policies of the segments are the same as those described in Note A. Intersegment sales are recorded on the same basis as sales to unaffiliated customers and are discussed in further detail in Note P. Net margin is comprised of total revenues less cost of sales and fuel. Cost of sales and fuel includes commodity purchases, fuel, and storage and transportation costs.
Customers - In 2012, 2011 and 2010, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.
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Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:
Year Ended December 31, 2012 | ONEOK Partners (a) | Natural Gas Distribution | Energy Services | Other and Eliminations | Total | |||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||
Sales to unaffiliated customers | $ | 9,830,052 | $ | 1,379,366 | $ | 1,421,171 | $ | 1,970 | $ | 12,632,559 | ||||||||||
Intersegment revenues | 352,099 | (2,717 | ) | 105,402 | (454,784 | ) | — | |||||||||||||
Total revenues | $ | 10,182,151 | $ | 1,376,649 | $ | 1,526,573 | $ | (452,814 | ) | $ | 12,632,559 | |||||||||
Net margin | $ | 1,641,832 | $ | 756,389 | $ | (49,344 | ) | $ | 1,964 | $ | 2,350,841 | |||||||||
Operating costs | 482,540 | 410,572 | 17,950 | (2,084 | ) | 908,978 | ||||||||||||||
Depreciation and amortization | 203,101 | 130,150 | 361 | 2,232 | 335,844 | |||||||||||||||
Goodwill impairment | — | — | 10,255 | — | 10,255 | |||||||||||||||
Gain on sale of assets | 6,736 | — | — | — | 6,736 | |||||||||||||||
Operating income | $ | 962,927 | $ | 215,667 | $ | (77,910 | ) | $ | 1,816 | $ | 1,102,500 | |||||||||
Equity earnings from investments | $ | 123,024 | $ | — | $ | — | $ | — | $ | 123,024 | ||||||||||
Investments in unconsolidated affiliates | $ | 1,221,405 | $ | — | $ | — | $ | — | $ | 1,221,405 | ||||||||||
Total assets | $ | 10,959,230 | $ | 3,535,489 | $ | 493,006 | $ | 867,550 | $ | 15,855,275 | ||||||||||
Noncontrolling interests in consolidated subsidiaries | $ | 4,767 | $ | — | $ | — | $ | 2,098,074 | $ | 2,102,841 | ||||||||||
Capital expenditures | $ | 1,560,513 | $ | 280,294 | $ | — | $ | 25,346 | $ | 1,866,153 | ||||||||||
(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had
revenues of $722.1 million, net margin of $618.0 million and operating income of $375.6 million.
Year Ended December 31, 2011 | ONEOK Partners (a) | Natural Gas Distribution | Energy Services | Other and Eliminations | Total | |||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||
Sales to unaffiliated customers | $ | 10,919,004 | $ | 1,609,628 | $ | 2,274,799 | $ | 2,363 | $ | 14,805,794 | ||||||||||
Intersegment revenues | 403,603 | 11,706 | 502,418 | (917,727 | ) | — | ||||||||||||||
Total revenues | $ | 11,322,607 | $ | 1,621,334 | $ | 2,777,217 | $ | (915,364 | ) | $ | 14,805,794 | |||||||||
Net margin | $ | 1,577,380 | $ | 751,835 | $ | 48,740 | $ | 2,404 | $ | 2,380,359 | ||||||||||
Operating costs | 459,364 | 422,073 | 24,527 | 2,359 | 908,323 | |||||||||||||||
Depreciation and amortization | 177,549 | 132,212 | 445 | 1,954 | 312,160 | |||||||||||||||
Loss on sale of assets | (963 | ) | — | — | — | (963 | ) | |||||||||||||
Operating income | $ | 939,504 | $ | 197,550 | $ | 23,768 | $ | (1,909 | ) | $ | 1,158,913 | |||||||||
Equity earnings from investments | $ | 127,246 | $ | — | $ | — | $ | — | $ | 127,246 | ||||||||||
Investments in unconsolidated affiliates | $ | 1,223,398 | $ | — | $ | — | $ | — | $ | 1,223,398 | ||||||||||
Total assets | $ | 8,946,676 | $ | 3,392,475 | $ | 562,728 | $ | 794,756 | $ | 13,696,635 | ||||||||||
Noncontrolling interests in consolidated subsidiaries | $ | 5,112 | $ | — | $ | — | $ | 1,556,047 | $ | 1,561,159 | ||||||||||
Capital expenditures | $ | 1,063,383 | $ | 242,590 | $ | 41 | $ | 30,053 | $ | 1,336,067 | ||||||||||
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had
revenues of $658.5 million, net margin of $469.0 million and operating income of $232.8 million.
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Year Ended December 31, 2010 | ONEOK Partners (a) | Natural Gas Distribution | Energy Services | Other and Eliminations | Total | |||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||
Sales to unaffiliated customers | $ | 8,218,160 | $ | 1,810,502 | $ | 2,647,460 | $ | 2,669 | $ | 12,678,791 | ||||||||||
Intersegment revenues | 457,740 | 6,900 | 653,717 | (1,118,357 | ) | — | ||||||||||||||
Total revenues | $ | 8,675,900 | $ | 1,817,402 | $ | 3,301,177 | $ | (1,115,688 | ) | $ | 12,678,791 | |||||||||
Net margin | $ | 1,144,853 | $ | 754,917 | $ | 159,739 | $ | 2,661 | $ | 2,062,170 | ||||||||||
Operating costs | 403,476 | 398,861 | 28,384 | 192 | 830,913 | |||||||||||||||
Depreciation and amortization | 173,708 | 130,968 | 694 | 1,854 | 307,224 | |||||||||||||||
Gain (loss) on sale of assets | 18,632 | (13 | ) | — | — | 18,619 | ||||||||||||||
Operating income | $ | 586,301 | $ | 225,075 | $ | 130,661 | $ | 615 | $ | 942,652 | ||||||||||
Equity earnings from investments | $ | 101,880 | $ | — | $ | — | $ | — | $ | 101,880 | ||||||||||
Investments in unconsolidated affiliates | $ | 1,188,124 | $ | — | $ | — | $ | — | $ | 1,188,124 | ||||||||||
Total assets | $ | 7,920,100 | $ | 3,237,890 | $ | 651,960 | $ | 689,225 | $ | 12,499,175 | ||||||||||
Noncontrolling interests in consolidated subsidiaries | $ | 5,176 | $ | — | $ | — | $ | 1,467,042 | $ | 1,472,218 | ||||||||||
Capital expenditures | $ | 352,714 | $ | 215,608 | $ | 488 | $ | 13,938 | $ | 582,748 | ||||||||||
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had
revenues of $612.2 million, net margin of $479.1 million and operating income of $250.9 million.
S. QUARTERLY FINANCIAL DATA (UNAUDITED)
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
Year Ended December 31, 2012 | ||||||||||||||||
(Thousands of dollars except per share amounts) | ||||||||||||||||
Total revenues | $ | 3,414,600 | $ | 2,529,260 | $ | 3,028,775 | $ | 3,659,924 | ||||||||
Net margin | $ | 643,587 | $ | 548,962 | $ | 553,972 | $ | 604,320 | ||||||||
Income from continuing operations | $ | 219,450 | $ | 148,938 | $ | 164,988 | $ | 195,875 | ||||||||
Income from discontinued operations and gain on sale, net of tax | $ | 14,012 | $ | 267 | $ | — | $ | — | ||||||||
Net income | $ | 233,462 | $ | 149,205 | $ | 164,988 | $ | 195,875 | ||||||||
Net income attributable to ONEOK | $ | 122,865 | $ | 60,993 | $ | 65,219 | $ | 111,542 | ||||||||
Earnings per share total | ||||||||||||||||
Basic | $ | 0.59 | $ | 0.29 | $ | 0.32 | $ | 0.55 | ||||||||
Diluted | $ | 0.58 | $ | 0.29 | $ | 0.31 | $ | 0.53 | ||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||
(Thousands of dollars except per share amounts) | ||||||||||||||||
Total revenues | $ | 3,760,600 | $ | 3,444,798 | $ | 3,529,359 | $ | 4,071,037 | ||||||||
Net margin | $ | 629,877 | $ | 518,833 | $ | 532,624 | $ | 699,025 | ||||||||
Income from continuing operations | $ | 198,285 | $ | 134,329 | $ | 161,159 | $ | 263,741 | ||||||||
Income (loss) from discontinued operations, net of tax | $ | 1,061 | $ | 437 | $ | (278 | ) | $ | 1,010 | |||||||
Net income | $ | 199,346 | $ | 134,767 | $ | 160,880 | $ | 264,751 | ||||||||
Net income attributable to ONEOK | $ | 130,130 | $ | 55,142 | $ | 60,321 | $ | 115,001 | ||||||||
Earnings per share total | ||||||||||||||||
Basic | $ | 0.61 | $ | 0.26 | $ | 0.29 | $ | 0.56 | ||||||||
Diluted | $ | 0.595 | $ | 0.25 | $ | 0.28 | $ | 0.55 | ||||||||
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rule 13a-15(b) of the Exchange Act.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2012.
Our internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein (Item 8).
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors of the Registrant
Information concerning our directors is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
Executive Officers of the Registrant
Information concerning our executive officers is included in Part I, Item 1, Business, of this Annual Report.
Compliance with Section 16(a) of the Exchange Act
Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
Code of Ethics
Information concerning the code of ethics, or code of business conduct, is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
Nominating Committee Procedures
Information concerning the Nominating Committee procedures is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
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Audit Committee
Information concerning the Audit Committee is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
Audit Committee Financial Experts
Information concerning the Audit Committee Financial Experts is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Security Ownership of Certain Beneficial Owners
Information concerning the ownership of certain beneficial owners is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
Security Ownership of Management
Information on security ownership of directors and officers is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
Equity Compensation Plan Information
The following table sets forth certain information concerning our equity compensation plans as of December 31, 2012:
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities in Column (a)) | |||||||||||
Plan Category | (a) | (b) | (c) | ||||||||||
Equity compensation plans approved by security holders (1) | 3,300,215 | $ | 29.61 | 7,847,642 | |||||||||
Equity compensation plans not approved by security holders (2) | 498,728 | $ | 42.75 | (3) | 1,007,204 | ||||||||
Total | 3,798,943 | $ | 31.33 | 8,854,846 | |||||||||
(1) - Includes shares granted under our Employee Stock Purchase Plan, and Employee Stock Award Program, and stock options, restricted stock incentive units and performance-unit awards granted under our Long-Term Incentive Plan and Equity Compensation Plan. For a brief description of the material features of these plans, see Note L of the Notes to Consolidated Financial Statements in this Annual Report. Column (c) includes 2,521,982, 263,489, 1,300,732 and 3,761,439 shares available for future issuance under our Employee Stock Purchase Plan, Employee Stock Award Program, Long-Term Incentive Plan and Equity Compensation Plan, respectively.
(2) - Includes our Employee Non-Qualified Deferred Compensation Plan, Deferred Compensation Plan for Non-Employee Directors and Stock Compensation Plan for Non-Employee Directors. For a brief description of the material features of these plans, see Note L of the Notes to Consolidated Financial Statements in this Annual Report.
(3) - Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for Non-Employee Directors is distributed to participants at fair market value on the date of distribution. The price used for these plans to calculate the weighted-average exercise price in the table is $42.75, which represents the year-end closing price of our common stock on the NYSE.
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ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information on certain relationships and related transactions and director independence is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Information concerning the principal accountant’s fees and services is set forth in our 2013 definitive Proxy Statement and is incorporated herein by this reference.
PART IV.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(1) Financial Statements | Page No. | ||
(a) | Report of Independent Registered Public Accounting Firm | 79 | |
(b) | Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010 | 80 | |
(c) | Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010 | 81 | |
(d) | Consolidated Balance Sheets as of December 31, 2012 and 2011 | 82-83 | |
(e) | Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 | 85 | |
(f) | Consolidated Statements of Shareholder’s Equity for the years ended December 31, 2012, 2011 and 2010 | 86-87 | |
(g) | Notes to Consolidated Financial Statements | 88-129 | |
(2) Financial Statements Schedules | |||
All schedules have been omitted because of the absence of conditions under which they are required. | |||
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(3) Exhibits | ||
3 | Not used. | |
3.1 | Not used. | |
3.2 | Not used. | |
3.3 | Not used. | |
3.4 | Amended and Restated Bylaws of ONEOK, Inc. (incorporated by reference from Exhibit 99.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 20, 2009). | |
3.5 | Amended and Restated Certificate of Incorporation of ONEOK, Inc. dated May 15, 2008 (incorporated by reference from Exhibit 3.1 to ONEOK, Inc.’s Current Report on Form 8-K filed May 19, 2008). | |
3.6 | Certificate of Correction form dated November 5, 2008 (incorporated by reference from Exhibit 4.2 to Registration Statement on Form S-3 filed November 21, 2008). | |
4 | Certificate of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK, Inc.) filed November 21, 2008 (incorporated by reference from Exhibit 4.2 to ONEOK, Inc.’s Registration Statement on Form S-3 filed November 21, 2008, Commission File No. 333-155593). | |
4.1 | Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc. filed November 21, 2008 (incorporated by reference from Exhibit No. 4.2 to ONEOK, Inc.’s Registration Statement on Form S-3 filed November 21, 2008). | |
4.2 | Amendment dated May 23, 2012, to the ONEOK, Inc. Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to ONEOK, Inc.’s Current Report on Form 8-K filed on May 25, 2012). | |
4.3 | Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to ONEOK, Inc.’s Registration Statement on Form 8-A filed November 21, 1997). | |
4.4 | Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Registration Statement on Form S-3 filed August 26, 1998, Commission File No. 333-62279). | |
4.5 | Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Amendment No. 1 to ONEOK, Inc.’s Registration Statement on Form S-3 filed December 28, 2001, Commission File No. 333-65392). | |
4.6 | First Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(a) to ONEOK, Inc.’s Current Report on Form 8-K/A filed October 2, 1998). | |
4.7 | Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(b) to ONEOK, Inc.’s Current Report on Form 8-K/A filed October 2, 1998). | |
4.8 | Second Amended and Restated Rights Agreement, dated March 31, 2011, between ONEOK, Inc. and Wells Fargo Bank, N.A. as Rights Agent (incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed May 5, 2011). | |
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4.9 | Fourth Supplemental Indenture dated February 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.5 to ONEOK, Inc.’s Registration Statement on Form S-3 filed April 15, 1999, Commission File No. 333-76375). | |
4.10 | Not used. | |
4.11 | Not used. | |
4.12 | Eighth Supplemental Indenture dated April 6, 2001, between ONEOK, Inc. and The Chase Manhattan Bank (incorporated by reference from Exhibit 4.9 to ONEOK, Inc.’s Registration Statement on Form S-3 filed July 19, 2001, Commission File No. 333-65392). | |
4.13 | Not used. | |
4.14 | Second Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Current Report on Form 8-K filed June 17, 2005). | |
4.15 | Third Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.3 to ONEOK, Inc.’s Current Report on Form 8-K filed June 17, 2005). | |
4.16 | Not used. | |
4.17 | Not used. | |
4.18 | Not used. | |
4.19 | Indenture, dated September 25, 2006, between ONEOK Partners, L.P. and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 26, 2006 (File No. 1-12202)). | |
4.20 | Eighth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 2.000% Senior Notes due 2017 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)). | |
4.21 | Second Supplemental Indenture, dated September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.15 percent Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 26, 2006 (File No. 1-12202)). | |
4.22 | Third Supplemental Indenture, dated September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.65 percent Senior Notes due 2036 (incorporated by reference to Exhibit 4.4 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 26, 2006 (File No. 1-12202)). | |
4.23 | Fourth Supplemental Indenture, dated September 28, 2007, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.85 percent Senior Notes due 2037 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 28, 2007 (File No. 1-12202)). | |
4.24 | Fifth Supplemental Indenture, dated March 3, 2009, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 8.625 percent Senior Notes due 2019 (incorporated by reference to Exhibit 4.2 to ONEOK Partner, L.P.’s Current Report on Form 8-K filed March 3, 2009 (File No. 1-12202)) | |
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4.25 | Ninth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.375% Senior Notes due 2022 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)). | |
4.26 | Form of Class B unit certificate of ONEOK Partners, L.P. (incorporated by reference to Exhibit 4.1 to Northern Border Partners, L.P.’s Current Report on Form 8-K filed April 12, 2006 (File No. 1-12202)). | |
4.27 | Sixth Supplemental Indenture, dated January 26, 2011, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.250 percent Senior Notes due 2016 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed January 26, 2011 (File No. 1-12202)). | |
4.28 | Seventh Supplemental Indenture, dated January 26, 2011, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.125 percent Senior Notes due 2041 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed January 26, 2011 (File No. 1-12202)). | |
4.29 | Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26, 2012). | |
4.30 | First Supplemental Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee, with respect to the 4.25 percent Senior Notes due 2022 (incorporated by reference to Exhibit 4.2 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26, 2012). | |
10 | ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002). | |
10.1 | ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from Exhibit 99 to ONEOK, Inc.’s Registration Statement on Form S-8 filed January 25, 2001). | |
10.2 | ONEOK, Inc. Supplemental Executive Retirement Plan terminated and frozen December 31, 2004 (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed December 20, 2004). | |
10.3 | ONEOK, Inc. 2005 Supplemental Executive Retirement Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.3 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009). | |
10.4 | Not used. | |
10.5 | Form of Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers and directors, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.4 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003). | |
10.6 | Amended and Restated ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed May 27, 2009). | |
10.7 | ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, as amended and restated December 16, 2004 (incorporated by reference from Exhibit 10.3 to ONEOK, Inc.’s Current Report on Form 8-K filed December 20, 2004). | |
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10.8 | ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.8 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009). | |
10.9 | ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.9 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009). | |
10.10 | Not used. | |
10.11 | Not used. | |
10.12 | Credit Agreement, dated April 5, 2011, among ONEOK, Inc., as borrower, the lenders party thereto, Bank of America, N.A., as administrative agent, swing line lender, and a letter of credit issuer, and JPMorgan Chase Bank, N.A. and The Royal Bank of Scotland plc, as letter of credit issuers (incorporated by reference from Exhibit 10.1 to ONEOK Inc.’s Current Report on Form 8-K filed April 7, 2011 (File No. 001-13643)). | |
10.13 | Amended and Restated Limited Liability Company Agreement of Overland Pass Pipeline Company LLC entered into between ONEOK Overland Pass Holdings, L.L.C. and Williams Field Services Company, LLC dated May 31, 2006 (incorporated by reference to Exhibit 10.6 to ONEOK Partners, L.P.’s Quarterly Report on Form 10-Q for the period ended June 30, 2006, filed August 4, 2006 (File No. 1-12202)). | |
10.14 | Form of ONEOK, Inc. Officer Change in Control Severance Plan (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed July 22, 2011 (File No. 001-13643)). | |
10.15 | Not used. | |
10.16 | Amendment No. 1 to the Equity Distribution Agreement dated January 13, 2013, by and between ONEOK Partners, L.P. and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 1.2 to ONEOK Partners, L.P.’s Registration Statement on Form S-3 filed January 10, 2013 (File No. 1-12202)). | |
10.17 | Form of Restricted Unit Stock Bonus Award Agreement dated February 20, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Form 8-K filed February 25, 2013 (File No. 1-13643)). | |
10.18 | Form of Performance Unit Award Agreement dated February 20, 2013 (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Form 8-K filed February 25, 2013 (File No. 1-13643)). | |
10.19 | Form of Restricted Unit Stock Bonus Award Agreement dated February 15, 2012 (incorporated by reference to Exhibit 10.19 to ONEOK, Inc.’s Form 10-K filed February 21, 2012, for the fiscal year ended December 31, 2011. | |
10.20 | Form of Performance Unit Award Agreement dated February 15, 2012 (incorporated by reference to Exhibit 10.20 to ONEOK, Inc.’s Form 10-K filed February 21, 2012, for the fiscal year ended December 31, 2011. | |
10.21 | Not used. | |
10.22 | Underwriting Agreement dated February 28, 2012, among ONEOK Partners, L.P. and Barclays Capital Inc., Citigroup Global Capital Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed March 2, 2012 (File No. 1-12202)). | |
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10.23 | Common Unit Purchase Agreement dated February 28, 2012, between ONEOK Partners, L.P. and ONEOK, Inc. (incorporated by reference to Exhibit 1.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed March 2, 2012 (File No. 1-12202)). | |
10.24 | Equity Distribution Agreement dated November 13, 2012, by and among ONEOK Partners, L.P. and Citigroup Global Capital Markets Inc. (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed November 13, 2012 (File No. 1-12202 )). | |
10.25 | Purchase Agreement dated May 17, 2011, by and between ONEOK, Inc., and Barclays Bank PLC acting through Barclays Capital Inc. as agent (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Quarterly Report on Form 10-Q filed August 3, 2011 (File No. 001-13643)). | |
10.26 | Credit Agreement, dated August 1, 2011, among ONEOK Partners, L.P., as borrower, the lenders party thereto, Citibank, N.A., as administrative agent, swing line lender and a letter-of-credit issuer, and Barclays Bank and Wells Fargo Bank, N.A., as letter-of-credit issuers (incorporated by reference from Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed August 2, 2011 (File No. 001-12202)). | |
10.27 | Guaranty Agreement, dated August 1, 2011, by ONEOK Partners Intermediate Limited Partnership in favor of the Citibank, N.A., as administrative agent (incorporated by reference from Exhibit 10.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed August 2, 2011 (File No. 001-12202)). | |
10.28 | Underwriting Agreement dated January 23, 2012, among ONEOK, Inc. and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 4.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26, 2012). | |
10.29 | Underwriting Agreement, dated September 10, 2012, among ONEOK Partners, L.P. and ONEOK Partner Intermediate Limited Partnership and RBS Securities Inc., Mitsubishi UFJ Securities (USA), Inc. and U.S. Bancorp Investments, Inc., as representative of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)). | |
10.30 | Extension Agreement, dated August 1, 2012, among ONEOK Partners, L.P., as Borrower, the lenders party thereto and Citibank, N.A., as administrative agent, swing line lender and letter-of-credit issuer (incorporated by reference from Exhibit 10.1 to ONEOK Partners, L.P.’s Quarterly Report on 10-Q for the period ended June 30, 2012, filed August 1, 2012 (File No. 1-12202)). | |
10.31 | Not used. | |
10.32 | Services Agreement among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership executed April 6, 2006, but effective as of April 1, 2006 (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed April 12, 2006). | |
10.33 | Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated September 15, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 19, 2006 (File No. 1-12202)). | |
10.34 | Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed February 17, 2012 (File No. 1-12202)). | |
10.35 | Not used. | |
10.36 | Not used. | |
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10.37 | ONEOK, Inc. Profit Sharing Plan dated January 1, 2005 (incorporated by reference from Exhibit 99 to ONEOK, Inc.’s Registration Statement on Form S-8 filed December 30, 2004). | |
10.38 | Not used. | |
10.39 | Form of Non-Statutory Stock Option Agreement (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004). | |
10.40 | Not used. | |
10.41 | Not used. | |
10.42 | Not used. | |
10.43 | Not used. | |
10.44 | ONEOK, Inc. Equity Compensation Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.44 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009). | |
10.45 | Not used. | |
10.46 | Not used. | |
10.47 | Not used. | |
10.48 | Not used. | |
10.49 | Not used. | |
10.50 | Not used. | |
10.51 | Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated July 20, 2007 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Quarterly Report on Form 10-Q filed August 3, 2007 (File No. 001-12202)). | |
10.52 | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated July 12, 2011 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed July 12, 2011 (File No. 001-12202)). | |
10.53 | Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of ONEOK Partners GP, L.L.C. effective July 14, 2009 (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed February 17, 2012 (File No. 1-12202)). | |
10.54 | Not used. | |
10.55 | Not used. | |
10.56 | First Amended and Restated Limited Liability Company Agreement of ONEOK ILP GP, L.L.C. effective July 14, 2009 (incorporated by reference to Exhibit 99.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed July 17, 2009). | |
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10.57 | Form of Restricted Unit Stock Bonus Award Agreement dated February 18, 2010 (incorporated by reference from Exhibit 10.57 to ONEOK, Inc.’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2009, filed October 12, 2010). | |
10.58 | Form of Performance Unit Award Agreement dated February 18, 2010 (incorporated by reference from Exhibit 10.58 to ONEOK, Inc.’s Annual Report on Form 10-K/A for the fiscal year ended December 31, 2009, filed October 12, 2010). | |
10.59 | Form of Restricted Unit Stock Bonus Award Agreement (incorporated by reference from Exhibit 10.59 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, filed February 22, 2011). | |
10.60 | Form of Performance Unit Award Agreement (incorporated by reference from Exhibit 10.60 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, filed February 22, 2011). | |
10.61 | Accelerated Share Repurchase Agreement dated June 11, 2012, by and between ONEOK, Inc. and Goldman Sachs & Co. (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q filed August 1, 2012 (File No. 1-12202)). | |
10.62 | ONEOK, Inc. Employee Stock Purchase Plan as amended and restated effective May 23, 2012 (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Quarterly Report on Form 10-Q filed August 1, 2012 (File No. 1-12202)). | |
12 | Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2012, 2011, 2010, 2009 and 2008. | |
21 | Required information concerning the registrant’s subsidiaries. | |
23 | Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP. | |
31.1 | Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2 | Certification of Derek S. Reiners pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1 | Certification of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)). | |
32.2 | Certification of Derek S. Reiners pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)). | |
101.INS | XBRL Instance Document | |
101.SCH | XBRL Taxonomy Extension Schema Document | |
101.CAL | XBRL Taxonomy Calculation Linkbase Document | |
101.DEF | XBRL Taxonomy Extension Definitions Document | |
101.LAB | XBRL Taxonomy Label Linkbase Document | |
101.PRE | XBRL Taxonomy Presentation Linkbase Document | |
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Attached as Exhibit 101 to this Annual Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010; (iv) Consolidated Balance Sheets at December 31, 2012 and 2011; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; (vi) Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2012, 2011 and 2010; and (vii) Notes to Consolidated Financial Statements.
We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 26, 2013 | ONEOK, Inc. | |
Registrant | ||
By: | /s/ Derek S. Reiners | |
Derek S. Reiners | ||
Senior Vice President, | ||
Chief Financial Officer and Treasurer | ||
Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 26th day of February 2013.
/s/ John W. Gibson | /s/ Derek S. Reiners | ||
John W. Gibson | Derek S. Reiners | ||
Chairman and | Senior Vice President, | ||
Chief Executive Officer | Chief Financial Officer and Treasurer | ||
/s/ Sheppard F. Miers III | /s/ James C. Day | ||
Sheppard F. Miers III | James C. Day | ||
Vice President and | Director | ||
Chief Accounting Officer | |||
/s/ Julie H. Edwards | /s/ William L. Ford | ||
Julie H. Edwards | William L. Ford | ||
Director | Director | ||
/s/ Bert H. Mackie | /s/ Steven J. Malcolm | ||
Bert H. Mackie | Steven J. Malcolm | ||
Director | Director | ||
/s/ Jim W. Mogg | /s/ Pattye L. Moore | ||
Jim W. Mogg | Pattye L. Moore | ||
Director | Director | ||
/s/ Gary D. Parker | /s/ Eduardo A. Rodriguez | ||
Gary D. Parker | Eduardo A. Rodriguez | ||
Director | Director | ||
/s/ Gerald B. Smith | |||
Gerald B. Smith | |||
Director | |||
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