UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event report): May 8, 2003
DEVON ENERGY CORPORATION
| DELAWARE (State or Other Jurisdiction of Incorporation or Organization) |
000-30176 (Commission File Number) |
73-1567067 (IRS Employer Identification Number) |
| 20 NORTH BROADWAY, OKLAHOMA CITY, OK (Address of Principal Executive Offices) |
73102 (Zip Code) |
Registrant’s telephone number, including area code: (405) 235-3611
Page 1 of 16 pages
Item 5. Other Events
Definitions
The following discussion includes references to various abbreviations relating to volumetric production terms and other defined terms. These definitions are as follows:
“AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. system.
“Bbl” or “Bbls” means barrel or barrels.
“Bcf” means billion cubic feet.
“Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
“Brent” means pricing point for selling North Sea crude oil.
“Btu” means British thermal units, a measure of heating value.
“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“MMBbls” means one million Bbls.
“MMBoe” means one million Boe.
“MMBtu” means one million Btu.
“Mcf” means one thousand cubic feet.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“Oil” includes crude oil and condensate.
Forward-Looking Estimates
The forward-looking statements provided in this discussion are based on management’s examination of historical operating trends, the information which was used to prepare the December 31, 2002 reserve reports of independent petroleum engineers and other data in Devon’s possession or available from third parties. Also, the effects of the acquisition of Ocean Energy, Inc. (“Ocean”), which closed on April 25, 2003, is included in the following estimates for the last eight months of the year. Devon cautions that its future oil, natural gas and NGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development, production and sale of oil, gas and NGLs. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below. Additionally, Devon cautions that its future marketing and midstream revenues and expenses are subject to all of the risks and uncertainties normally incident to the marketing and midstream business. These risks include, but are not limited to, price volatility, environmental risks, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipeline throughput, cost of goods and services and other risks as outlined below. Also, the financial results of Devon’s foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks.
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Specific Assumptions and Risks Related to Price and Production Estimates Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and worldwide economic conditions, weather and other local market conditions. These factors are beyond Devon’s control and are difficult to predict. In addition to volatility in general, Devon’s oil, gas and NGL prices may vary considerably due to differences between regional markets, transportation availability and costs and demand for the various products derived from oil, natural gas and NGLs. Substantially all of Devon’s revenues are attributable to sales, processing and transportation of these three commodities. Consequently, Devon’s financial results and resources are highly influenced by price volatility.
Estimates for Devon’s future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil, gas and NGLs will continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Also, Devon’s international production of oil, natural gas and NGLs is governed by payout agreements with the governments of the countries in which Devon operates. If the payout under these agreements is attained earlier than projected, Devon’s net production and proved reserves in such areas could be reduced.
Estimates for Devon’s future processing and transport of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil, gas and NGLs will continue at levels that allow for profitable processing and transport of these products. There can be no assurance of such stability.
The production, transportation, processing and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for Devon’s oil, natural gas and NGLs during 2003 will be substantially similar to those of 2002, unless otherwise noted.
Given the general limitations expressed herein, following are Devon’s forward-looking statements for 2003. Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Amounts related to Canadian operations have been converted to U.S. dollars using a projected exchange rate of $0.6906 U.S. dollar to $1.00 Canadian dollar. The actual 2003 exchange rate may vary materially from this estimated rate. Such variations could have a material effect on the following estimates.
Though Devon has completed several major property acquisitions and dispositions in recent years, these transactions are opportunity driven. Thus, the following forward-looking data excludes the financial and operating effects of potential property acquisitions or divestitures, except for the Ocean merger, during the year 2003.
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Geographic Reporting Areas for 2003
The following estimates of production, average price differentials and capital expenditures are provided separately for each of the following geographic areas:
| • | the United States; | ||
| • | Canada; and | ||
| • | International, which encompasses all oil and gas properties that lie outside of the United States and Canada. |
Year 2003 Potential Operating Items
Oil, Gas and NGL Production Set forth in the following paragraphs are individual estimates of Devon’s oil, gas and NGL production for 2003. On a combined basis, Devon estimates its 2003 oil, gas and NGL production will total between 220 and 234 MMBoe. Of this total, approximately 93% is estimated to be produced from reserves classified as “proved” at December 31, 2002.
Oil Production Devon expects its oil production in 2003 to total between 62 and 64 MMBbls. Of this total, approximately 94% is estimated to be produced from reserves classified as “proved” at December 31, 2002. The expected ranges of production by area are as follows:
| (MMBbls) | ||||
United States |
30 to 31 | |||
Canada |
14 to 14 | |||
International |
18 to 19 | |||
Oil Prices — Fixed Through various price swaps, Devon has fixed the price it will receive in 2003 on a portion of its oil production. The following table includes information on this fixed-price production by area. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the prices recorded by Devon.
| Months of | ||||||||||||
| Bbls/Day | Price/Bbl | Production | ||||||||||
International |
35,000 | $ | 26.88 | May - Dec | ||||||||
Oil Prices — Floating Devon’s 2003 average prices for each of its areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is the monthly average of settled prices on each trading day for West Texas Intermediate crude oil delivered at Cushing, Oklahoma.
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| Expected Range of Oil Prices | ||||
| Less than NYMEX Price | ||||
United States |
($3.00) to ($2.00) | |||
Canada |
($6.25) to ($4.25) | |||
International |
($5.50) to ($3.50) | |||
Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2003 oil production that otherwise is subject to floating prices. The floor and ceiling prices related to domestic and Canadian oil production are based on the NYMEX price. If the NYMEX price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s oil revenues for the period. Because Devon’s oil volumes are often sold at prices that differ from the NYMEX price due to differing quality (i.e., sweet crude versus sour crude) and transportation costs from different geographic areas, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
To simplify presentation, Devon’s costless collars as of April 30, 2003, have been aggregated in the following table according to similar floor prices and similar ceiling prices. The floor and ceiling prices shown are weighted averages of the various collars in each aggregated group.
| Weighted Average | ||||||||||||||||
| Floor | Ceiling | |||||||||||||||
| Area (Range of Floor Prices / | Price | Price | Months of | |||||||||||||
| Range of Ceiling Prices) | Bbls/Day | Per Bbl | Per Bbl | Production | ||||||||||||
United States ($20.00 - $22.75 / $27.05 - $28.65) |
18,000 | $ | 21.65 | $ | 27.91 | Jan - Dec | ||||||||||
United States ($23.25 - $23.50 / $28.25 - $30.00) |
8,000 | $ | 23.38 | $ | 29.12 | Jan - Dec | ||||||||||
United States ($23.50 - $23.50 / $28.25 - $30.75) |
6,000 | $ | 23.50 | $ | 29.31 | Jul - Dec | ||||||||||
Canada ($20.00 - $21.00 / $26.60 - $28.15) |
5,000 | $ | 20.40 | $ | 27.37 | Jan - Dec | ||||||||||
Canada ($22.00 - $22.75 / $27.00 - $28.40) |
13,000 | $ | 22.29 | $ | 27.52 | Jan - Dec | ||||||||||
Canada ($23.25 - $23.50 / $28.35 - $29.25) |
5,000 | $ | 23.30 | $ | 28.79 | Jan - Dec | ||||||||||
Canada ($23.50 - $23.50 / $28.80 - $29.75) |
3,000 | $ | 23.50 | $ | 29.18 | Jul - Dec | ||||||||||
Devon has also assumed a number of three-way collars from Ocean. A three-way collar is a combination of options—a sold put, a purchased put and a sold call. The purchased put establishes a floor price, unless the market price falls below the sold put, at which point the floor price would be NYMEX or Brent plus the difference between the purchased put and the sold put strike prices. The sold call establishes a ceiling price. The prices related to domestic oil production are based on the NYMEX price, and the prices related to international oil production are based on the Brent price. If the NYMEX or Brent price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s oil revenues for the period. Because Devon’s oil volumes are often sold at prices that differ from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus sour crude) and transportation costs from different geographic areas, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
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To simplify presentation, Devon’s three-way collars as of April 30, 2003, have been aggregated in the following table according to similar sold call prices. The sold call prices shown are weighted averages of the various collars in each aggregated group. The sold put price and the purchased put price are $19.00 per Bbl and $23.00 per Bbl, respectively, for each collar.
| Weighted Average | ||||||||||||||||||||
| Sold | Purchased | Sold | ||||||||||||||||||
| Put | Put | Call | ||||||||||||||||||
| Price | Price | Price | Months of | |||||||||||||||||
| Area (Range of Sold Call Prices) | Bbls/Day | Per Bbl | Per Bbl | Per Bbl | Production | |||||||||||||||
United States ($27.25 - $29.00) |
43,000 | $ | 19.00 | $ | 23.00 | $ | 27.98 | May - Dec | ||||||||||||
International ($27.13 - $27.30) |
10,000 | $ | 19.00 | $ | 23.00 | $ | 27.22 | May - Dec | ||||||||||||
Gas Production Devon expects its 2003 gas production to total between 845 Bcf and 859 Bcf. Of this total, approximately 92% is estimated to be produced from reserves expected to be classified as “proved” at December 31, 2002. The expected ranges of production by area are as follows:
| (Bcf) | ||||
United States |
580 to 587 | |||
Canada |
260 to 267 | |||
International |
5 to 5 | |||
Gas Prices — Fixed Through various price swaps and fixed-price physical delivery contracts, Devon has fixed the price it will receive in 2003 on a portion of its natural gas production. The following table includes information on this fixed-price production by area. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the prices recorded by Devon, and the prices have also been adjusted for the Btu content of the gas hedged.
| Months of | ||||||||||||
| Mcf/Day | Price/Mcf | Production | ||||||||||
United States |
97,148 | $ | 3.23 | Jan - Dec | ||||||||
United States |
196,000 | $ | 4.74 | May - Dec | ||||||||
Canada |
43,578 | $ | 2.33 | Jan - Jun | ||||||||
Canada |
43,578 | $ | 2.32 | Jul - Dec | ||||||||
Gas Prices — Floating For the natural gas production for which prices have not been fixed, Devon’s 2003 average prices for each of its areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is determined to be the first-of-month South Louisiana Henry Hub price index as published monthly in Inside FERC.
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| Expected Range of Gas Prices | ||||
| Less Than NYMEX Price | ||||
United States |
($1.00) to ($0.50) | |||
Canada |
($1.05) to ($0.55) | |||
International |
($3.00) to ($2.00) | |||
Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2003 natural gas production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
To simplify presentation, Devon’s costless collars have been aggregated in the following table according to similar floor prices and similar ceiling prices. The floor and ceiling prices shown are weighted averages of the various collars in each aggregated group.
The prices shown in the following table have been adjusted to a NYMEX-based price, using Devon’s estimates of 2003 differentials between NYMEX and the specific regional indices upon which the collars are based. The floor and ceiling prices related to the domestic collars are based on various regional first-of-the-month price indices as published monthly by Inside FERC. The floor and ceiling prices related to the Canadian collars are based on the AECO index as published by the Canadian Gas Price Reporter.
| Weighted | ||||||||||||||||
| Average | ||||||||||||||||
| Floor | Ceiling | |||||||||||||||
| Price | Price | |||||||||||||||
| Area (Range Of Floor Prices / | MMBtu/ | per | per | Months of | ||||||||||||
| Range of Ceiling Prices) | Day | MMBtu | MMBtu | Production | ||||||||||||
United States ($3.32 - $3.32 / $6.27 - $6.57) |
40,000 | $ | 3.32 | $ | 6.42 | Jan - Dec | ||||||||||
United States ($3.32 - $3.32 / $5.57 - $5.97) |
55,000 | $ | 3.32 | $ | 5.78 | Jan - Dec | ||||||||||
United States ($3.25 - $3.32 / $4.65 - $4.97) |
70,000 | $ | 3.30 | $ | 4.83 | Jan - Dec | ||||||||||
United States ($3.00 - $3.32 / $4.06 - $4.30) |
130,000 | $ | 3.15 | $ | 4.14 | Jan - Dec | ||||||||||
United States ($3.29 - $3.59 / $4.29 - $4.80) |
110,000 | $ | 3.46 | $ | 4.48 | Jan - Dec | ||||||||||
United States ($3.75 - $4.68 / $5.63 - $7.90) |
75,000 | $ | 4.31 | $ | 6.70 | Apr - Sep | ||||||||||
United States ($3.75 - $3.75 / $5.15 - $5.33) |
50,000 | $ | 3.75 | $ | 5.26 | May - Dec | ||||||||||
United States ($3.75 - $3.75 / $5.06 - $5.06) |
20,000 | $ | 3.75 | $ | 5.06 | May - Jun | ||||||||||
United States ($3.75 - $3.75 / $5.23 - $5.23) |
20,000 | $ | 3.75 | $ | 5.23 | Sep - Oct | ||||||||||
Canada ($3.56 - $3.68 / $7.36 - $7.65) |
20,000 | $ | 3.62 | $ | 7.50 | Jan - Dec | ||||||||||
Canada ($3.66 - $3.87 / $6.56 - $7.39) |
80,000 | $ | 3.79 | $ | 7.01 | Jan - Dec | ||||||||||
Canada ($3.57 - $3.61 / $4.39 - $4.39) |
80,000 | $ | 3.59 | $ | 4.39 | Jan - Dec | ||||||||||
Canada ($3.94 - $3.97 / $7.77 - $9.69) |
60,000 | $ | 3.96 | $ | 8.40 | Apr - Oct | ||||||||||
Canada ($3.82 - $3.84 / $5.27 - $6.41) |
50,000 | $ | 3.83 | $ | 5.87 | Jan - Dec | ||||||||||
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Devon has also assumed a number of three-way collars from Ocean. A three-way collar is a combination of options—a sold put, a purchased put and a sold call. The purchased put establishes a floor price, unless the market price falls below the sold put, at which point the floor price would be NYMEX plus the difference between the purchased put and the sold put strike prices. The sold call establishes a ceiling price. If the NYMEX price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at prices that differ from the NYMEX price due to differing Btu contents of gas produced, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
To simplify presentation, Devon’s three-way collars as of April 30, 2003, have been aggregated in the following table according to similar sold call prices. The sold call prices shown are weighted averages of the various collars in each aggregated group. The sold put price and the purchased put price are $2.50 per MMBtu and $3.50 per MMBtu, respectively, for each collar.
| Weighted Average | ||||||||||||||||||||
| Sold Put | Purchased | Sold Call | ||||||||||||||||||
| Price | Put | Price | ||||||||||||||||||
| Per | Price | Per | Months of | |||||||||||||||||
| Area (Range of Sold Call Prices) | MMBtu/Day | MMBtu | Per MMBtu | MMBtu | Production | |||||||||||||||
United States ($4.51 - $4.52) |
50,000 | $ | 2.50 | $ | 3.50 | $ | 4.52 | May - Dec | ||||||||||||
United States ($5.18 - $5.53) |
70,000 | $ | 2.50 | $ | 3.50 | $ | 5.34 | May - Dec | ||||||||||||
In 2000, Ocean received $75 million in exchange for quantities of natural gas to be delivered in 2003 and 2004. Under the terms of this forward sale, the purchaser is obligated to make additional payments in the event the spot price exceeds $2.50 per MMBtu in 2003 and $3.00 per MMBtu in 2004. The spot price is based on a relevant regional first-of-the-month price index as published monthly by Inside FERC as determined by Devon. In the Ocean merger, Devon assumed the obligation to deliver the contractual quantities (53,500 MMBtu per day in 2003 and 55,600 MMBtu per day in 2004). As part of the purchase price allocation, Devon has recorded deferred revenues related to this forward gas sale based on the $2.50/$3.00 prices. These deferred revenues will be recognized during the last eight months of 2003 and during the year 2004. If the monthly spot prices exceed these prices, Devon will receive additional cash payments from the purchaser, which will also be recorded as gas revenues. Therefore, if the monthly spot prices for the last eight months of 2003 exceed $2.50 per MMBtu, Devon will recognize gas revenues on the related quantities at a floating market price, but will receive actual cash payments equal only to the difference between the floating market price and $2.50. If the monthly spot prices for the last eight months of 2003 are equal to or less than $2.50 per MMBtu, Devon will recognize gas revenues on the related quantities at a fixed price of $2.50, and will receive no cash consideration for the delivered quantities of gas.
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NGL Production Devon expects its 2003 production of NGLs to total between 21 MMBbls and 22 MMBbls. Of this total, 96% is estimated to be produced from reserves expected to be classified as “proved” at December 31, 2002. The expected ranges of production by area are as follows:
| (MMBbls) | ||||
United States |
16 to 17 | |||
Canada |
5 to 5 | |||
Marketing and Midstream Revenues and Expenses Devon’s marketing and midstream revenues and expenses are derived primarily from its natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in response to several factors. The factors include, but are not limited to, changes in production from wells connected to the pipelines and related processing plants, changes in the absolute and relative prices of natural gas and NGLs, provisions of the contract agreements and the amount of repair and workover activity required to maintain anticipated processing levels.
These factors, coupled with uncertainty of future natural gas and NGL prices, increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses. Given these uncertainties, Devon estimates that 2003 marketing and midstream revenues will be between $1.19 billion and $1.23 billion and marketing and midstream expenses will be between $960 million and $1.0 billion.
Production and Operating Expenses Devon’s production and operating expenses include lease operating expenses, transportation costs and production taxes. These expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from Devon’s property base, changes in production tax rates, changes in the general price level of services and materials that are used in the operation of the properties and the amount of repair and workover activity required. Oil, natural gas and NGL prices also have an effect on lease operating expenses and impact the economic feasibility of planned workover projects.
Given these uncertainties, Devon estimates that 2003 lease operating expenses will be between $805 million and $845 million, transportation costs will be between $195 million and $205 million, and production taxes will be between 3.2% and 3.7% of consolidated oil, natural gas and NGL revenues, excluding revenues related to hedges upon which production taxes are not incurred.
Depreciation, Depletion and Amortization (“DD&A”) The 2003 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts in 2003 compared to the costs incurred for such efforts, and the revisions to Devon’s year-end 2002 reserve estimates (and its estimates of reserves acquired in April in the Ocean merger) that, based on prior experience, are likely to be made during 2003.
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Given these uncertainties, oil and gas property related DD&A expense for 2003 is expected to be between $1.5 billion and $1.6 billion. Additionally, Devon expects its DD&A expense related to non-oil and gas property fixed assets to total between $120 million and $130 million. This range includes $65 million to $70 million related to marketing and midstream assets. Based on these DD&A amounts and the production estimates set forth earlier, Devon expects its consolidated DD&A rate will be between $7.30 per Boe and $7.65 per Boe.
Accretion of Asset Retirement Obligation Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants. The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation for settlement. The initial measurement of the asset retirement obligation is to be the discounted present fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.” Because the asset retirement obligation is a discounted value, accretion will be recognized as the estimated date for settling the obligation draws closer.
As a result of the requirements of SFAS No. 143, Devon expects its 2003 accretion of its asset retirement obligation to be between $30 million and $40 million.
General and Administrative Expenses (“G&A”) Devon’s G&A includes the costs of many different goods and services used in support of its business. These goods and services are subject to general price level increases or decreases. In addition, Devon’s G&A varies with its level of activity and the related staffing needs as well as with the amount of professional services required during any given period. Should Devon’s needs or the prices of the required goods and services differ significantly from current expectations, actual G&A could vary materially from the estimate. The Ocean merger has further added to the uncertainties around G&A estimates. Devon is currently in the process of determining the appropriate staffing needs for the combined entity. Until this process is complete, actual 2003 G&A could vary materially from current estimates. Given these limitations, consolidated G&A in 2003 is expected to be between $270 million and $300 million.
Expenses Related to Mergers As a result of the Ocean merger, Devon is in the process of determining the appropriate staffing needs of the combined entity. Certain costs, such as severance or relocation costs related to employees of Devon prior to the merger, will be expensed. Until the evaluation process is complete, it is difficult to predict the amount of merger costs that will be expensed in 2003. However, it is expected that such costs will not exceed $10 million.
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Reduction of Carrying Value of Oil and Gas Properties Devon follows the full cost method of accounting for its oil and gas properties. Under the full cost method, Devon’s net book value of oil and gas properties, less related deferred income taxes (the “costs to be recovered”), may not exceed a calculated “full cost ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues from oil and gas properties plus the cost of properties not subject to amortization. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The costs to be recovered are compared to the ceiling on a quarterly basis. If the costs to be recovered exceed the ceiling, the excess is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than Devon’s long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Because of the volatile nature of oil and gas prices, it is not possible to predict whether Devon will incur a full cost writedown in future periods.
Interest Expense Future interest rates, debt outstanding and oil, natural gas and NGL prices have a significant effect on Devon’s interest expense. Devon can only marginally influence the prices it will receive in 2003 from sales of oil, natural gas and NGLs and the resulting cash flow. These factors increase the margin of error inherent in estimating future interest expense. Other factors which affect interest expense, such as the amount and timing of capital expenditures, are within Devon’s control.
Assuming no changes in fixed-rate debt balances during 2003, Devon’s average balance of fixed-rate debt during 2003 will be $7.3 billion. This average balance assumes that Devon’s average balance for the first four months of 2003 remains at $6.5 billion and the average balance for the last eight months, after the Ocean merger, is $7.8 billion. The interest expense in 2003 related to this fixed-rate debt, including net accretion of related discounts, will be approximately $513 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of Devon’s long-term debt. Devon’s floating rate debt is discussed in the following paragraphs.
As of March 31, 2003, Devon had $1.1 billion outstanding under its original $3.0 billion amortizing senior unsecured term loan credit facility. This credit facility, which was entered into in October 2001, has a term of five years. This credit facility is non-revolving.
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The remaining balance outstanding as of March 31, 2003 will mature as follows:
| (In millions) | ||||
April 15, 2006 |
$ | 335 | ||
October 15, 2006 |
800 | |||
| $ | 1,135 | |||
This $3 billion facility includes various rate options which can be elected by Devon, including a rate based on LIBOR plus a margin. The margin is based on Devon’s debt rating. Based on Devon’s current debt rating, the margin is 100 basis points. As of March 31, 2003, the average interest rate on this facility was 2.4%.
From time to time, Devon borrows under its $1 billion credit facilities. Borrowings under the U.S. facility, currently set at $725 million, may be borrowed at various rate options including LIBOR plus a margin with interest periods of up to six months. Borrowings under the Canadian facility, currently set at $275 million, may be made at various rate options including LIBOR plus a margin with interest periods up to six months, or Bankers Acceptances plus a margin with interest periods of 30 to 180 days. The current LIBOR margin ranges from 45 to 125 basis points based upon usage and the tranche utilized, and the current Bankers Acceptance margin is 72.5 basis points over the cost of funding. There were no borrowings under these facilities at March 31, 2003.
From time to time, Devon also borrows under its commercial paper facility. Total borrowings under the $725 million U.S. facility and the commercial paper program cannot exceed $725 million. There were no borrowings under the commercial paper facility as of March 31, 2003. Commercial paper borrowing costs are typically 20 to 50 basis points over LIBOR. Debt outstanding under this program is generally borrowed for seven to 90 day periods, and may be borrowed up to 365 days, at prevailing commercial paper market rates.
Devon has fixed the interest rate on $125 million Canadian dollars and $50 million U.S. dollars of its floating rate debt through swap agreements at average rates of 6.4% and 5.9%, respectively. The Canadian dollar swap agreements mature at various dates through July 2007 and the U.S. dollar swap agreement matures in May 2003.
Devon has also entered into an interest rate swap on its $125 million 8.05% senior notes due in 2004 to swap a fixed interest rate for a variable interest rate. The variable interest rate on this instrument is based on LIBOR plus a margin of 336 basis points. The interest rate swap is accounted for as a fair value hedge under SFAS 133.
Devon also assumed interest rate swaps in the Ocean merger on $100 million, 7.875% senior notes due in August 2003, and on $125 million, 7.625% senior notes due in 2005. These instruments swap a fixed interest rate for a variable interest rate. The variable interest rate on the 7.875% and 7.625% instruments is based on LIBOR plus a margin of 317 basis points and 237 basis points, respectively. These interest rate swaps are accounted for as fair value hedges under SFAS 133.
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Devon’s interest expense totals have historically included payments of facility and agency fees, amortization of debt issuance costs, the effect of the interest rate swaps, and other miscellaneous items not related to the debt balances outstanding. Devon expects between $15 million and $25 million of such items to be included in its 2003 interest expense. Also, Devon expects to capitalize between $15 million and $20 million of interest during 2003. Based on the information related to interest expense set forth herein and assuming no material changes in Devon’s levels of indebtedness or prevailing interest rates, Devon expects its 2003 interest expense will be between $545 million and $555 million.
Dividends on Subsidiary’s Preferred Stock Devon assumed Ocean’s convertible preferred stock which pays an annual dividend of 6.5%. As a result, Devon expects to pay $2 million in 2003 for dividends. Because the preferred stock is that of a Devon subsidiary, the dividend payments will be recorded as an expense on Devon’s statement of operations.
Effects of Changes in Foreign Currency Rates Devon’s Canadian subsidiary has $400 million of fixed-rate senior notes which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar during 2003 will increase or decrease the Canadian dollar equivalent balance of this debt. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. Because of the variability of the exchange rate, it is not possible to estimate the effect which will be recorded in 2003. However, based on the December 31, 2002, Canadian-to-U.S. dollar exchange rate of $0.6331, for every $0.01 change in the exchange rate, Devon will record an effect (either income or expense) of approximately $10 million Canadian dollars. The resulting revenue or expense in U.S. dollars will depend on the currency exchange rate in effect throughout the year.
Other Revenues Devon’s other revenues in 2003 are expected to be between $25 million and $30 million.
Income Taxes Devon’s financial income tax rate in 2003 will vary materially depending on the actual amount of financial pre-tax earnings. The tax rate for 2003 will be significantly affected by the proportional share of consolidated pre-tax earnings generated by U.S., Canadian and International operations due to the different tax rates of each country. There are certain tax deductions and credits that will have a fixed impact on 2003’s income tax expense regardless of the level of pre-tax earnings that are produced. Given the uncertainty of its pre-tax earnings amount, Devon estimates that its consolidated financial income tax rate in 2003 will be between 25% and 45%. The current income tax rate is expected to be between 5% and 15%. The deferred income tax rate is expected to be between 20% and 30%. Significant changes in estimated capital expenditures, production levels of oil, gas and NGLs, the prices of such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of the aforementioned tax deductions and credits on 2003’s financial income tax rates.
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Year 2003 Potential Capital Sources, Uses and Liquidity
Capital Expenditures Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not “budget”, nor can it reasonably predict, the timing or size of such possible acquisitions, except the Ocean merger, if any.
Devon’s capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from Devon’s price expectations for its future production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2003 capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon’s estimates.
Given the limitations discussed, the company expects its 2003 capital expenditures for drilling and development efforts, plus related facilities, to total between $2.0 billion and $2.2 billion. These amounts include between $790 million and $870 million for drilling and facilities costs related to reserves classified as proved as of year-end 2002. In addition, these amounts include between $535 million and $595 million for other low risk/reward projects and between $625 million and $695 million for new, higher risk/reward projects. Low risk/reward projects include development drilling that does not offset currently productive units and for which there is not a certainty of continued production from a known productive formation. Higher risk/reward projects include exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs.
The following table shows expected drilling and facilities expenditures by geographic area.
Drilling and Production Facilities Expenditures
| United States | Canada | International | Total | |||||||||||||
| ($ in millions) | ||||||||||||||||
Related to Proved Reserves |
$ | 540-$580 | $ | 110-$130 | $ | 140-$160 | $ | 790-$870 | ||||||||
Lower Risk/Reward Projects |
$ | 340-$370 | $ | 165-$185 | $ | 30-$40 | $ | 535-$595 | ||||||||
Higher Risk/Reward Projects |
$ | 340-$370 | $ | 220-$250 | $ | 65-$75 | $ | 625-$695 | ||||||||
Total |
$ | 1,220-$1,320 | $ | 495-$565 | $ | 235-$275 | $ | 1,950-$2,160 | ||||||||
In addition to the above expenditures for drilling and development, Devon expects to spend between $125 million to $150 million on its marketing and midstream assets, which include its oil pipelines, gas processing plants, CO2 removal facilities and gas transport pipelines. Devon also expects to capitalize between $110 million and $130 million of G&A expenses in accordance with the full cost method of accounting. Devon
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also expects to pay between $45 million and $55 million for plugging and abandonment charges, and to spend between $55 million and $65 million for other non-oil and gas property fixed assets.
Other Cash Uses Devon’s management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.05 per share quarterly dividend rate and 231 million shares of common stock outstanding after the merger, 2003 dividends are expected to approximate $43 million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay $10 million of dividends in 2003.
Capital Resources and Liquidity Devon’s estimated 2003 cash uses, including its drilling and development activities, are expected to be funded primarily through a combination of working capital and operating cash flow, with the remainder, if any, funded with borrowings from Devon’s credit facilities. The amount of operating cash flow to be generated during 2003 is uncertain due to the factors affecting revenues and expenses as previously cited. However, Devon expects its combined capital resources to be more than adequate to fund its anticipated capital expenditures and other cash uses for 2003. Currently, considering the effect of the Ocean merger and the expected renewal of our $1 billion credit facilities in June 2003, Devon will have $860 million available under these credit facilities, net of $140 million of outstanding letters of credit. If significant acquisitions or other unplanned capital requirements arise during the year, Devon could utilize its existing credit facilities and/or seek to establish and utilize other sources of financing.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.
| DEVON ENERGY CORPORATION | ||||
| By: | /s/ Danny J. Heatly | |||
| Danny J. Heatly Vice President — Accounting |
||||
Date: May 8, 2003
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