•	Significantly warmer weather across service territories reduces utility business reported earnings to $29.8 million.

•	Construction materials group narrows seasonal loss with 38 percent improvement in first quarter results, best performance since 2007.

•	Construction services and construction materials groups have nearly $1 billion combined backlog.

•	Pipeline group commenced operations at Dakota Prairie refinery, first U.S. refinery built in nearly 40 years.

•	Utility group has record five-year capital investment program, which is expected to result in 11 percent compound annual growth rate in rate base.

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•	Adjusted earnings per share for 2015 are projected in the range of $1.05 to $1.20. Adjusted earnings excludes the effects of the exploration and production segment.

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GAAP guidance for 2015 is a loss per share in the range of 65 cents to 80 cents. GAAP guidance includes the first quarter ceiling test impairment and excludes any future potential ceiling test impairments related to lower commodity prices. Given the current oil and natural gas pricing environment, the company believes it is likely it will have additional noncash ceiling test write-downs of its oil and natural gas properties in 2015. The quarterly ceiling test considers many factors including reserves, capital expenditure estimates and trailing 12-month average prices. Securities and Exchange Commission Defined Prices for each quarter of the previous 12 months were as follows:

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•	The company's long-term compound annual growth goals on adjusted earnings per share from operations are in the range of 7 to 10 percent.

•	The company continually seeks opportunities to expand through organic growth opportunities and strategic acquisitions.

•	The company focuses on creating value through vertical integration between its business units.

•	Estimated capital expenditures for 2015 through 2019 are noted in the following table:

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Rate base growth is projected to be approximately 11 percent compounded annually over the next five years, including plans for an approximate $1.8 billion gross capital investment program with $477 million planned for 2015. Although a prolonged period of lower commodity prices may slow Bakken-area growth in the future, the company continues to see strong current growth with increases of 4.4 percent in electric customer counts and 3.6 percent in natural gas customers in the first quarter compared to a year ago in this area.

•	Regulatory actions

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July 10 the North Dakota Public Service Commission approved recovery of $8.6 million annually effective July 15 to reflect actual costs incurred through February 2014 and projected costs through June 2015 for an environmental cost recovery rider related to costs resulting from the retrofit required to be installed at the Big Stone Station. The company's share of the cost for the installation is approximately $90 million and is expected to be complete in 2015. The commission had earlier approved advance determination of prudence for recovery of costs on the system.

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Aug. 11 the company filed an application with the Montana Public Service Commission for a natural gas rate increase of approximately $3.0 million annually, or 3.6 percent. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. An interim increase of $2.0 million annually was approved and implemented for service effective Feb. 6 subject to refund. A settlement has been reached with the consumer counsel stipulating a $2.5 million annual increase and the commission approved the stipulated increase April 28.

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Nov. 14 the company filed an application with the NDPSC for approval to implement the rate adjustment associated with the electric generation resource recovery rider previously approved by the commission. The rider was established to recover costs associated with new generation such as the Heskett III 88-MW natural gas combustion turbine. The commission approved rate adjustments of $5.3 million annually, which were implemented Jan. 9.

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Oct. 3 the company filed an application with the Wyoming Public Service Commission for a natural gas rate increase of approximately $788,000 annually, or 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. The company and the consumer advocacy group filed a stipulation agreement that resolved all issues between the parties for an increase of $501,000 annually. A hearing is scheduled for May 19.

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Dec. 22 the company filed for advanced determination of prudence with the NDPSC on the Thunder Spirit Wind project. A hearing is scheduled for May 14. The company recently signed an agreement to purchase the project, which includes 43 wind turbines totaling 107.5 MW of electric generation at a cost of approximately $200 million with approximately $55 million already funded in 2014. The project is being developed by ALLETE Clean Energy with an expected completion in December 2015.

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Feb. 6 the company filed an application with the NDPSC for a natural gas rate increase of approximately $4.3 million annually, or 3.4 percent above current rates. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. An interim increase of $4.3 million annually was implemented for service effective April 7, subject to refund. A hearing is scheduled for July 20.

◦	March 31 the company filed an application with the Oregon Public Utility Commission for a natural gas rate increase of approximately $3.6 million, or 5.1 percent above current rates. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses, as well as environmental remediation expenses.

◦	April 10 the company filed an update with the NDPSC to the environmental cost recovery rider for a total of $8.1 million for new rates effective July 1, 2015 through June 30, 2016. The requested recovery includes costs for the Big Stone and Lewis and Clark station environmental upgrades.

◦	The company expects to file electric rate cases in Montana, South Dakota and Wyoming and natural gas rate cases in Washington, Minnesota and South Dakota.

•	Investments of approximately $60 million are being made to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is higher than the national average. This reflects a slightly lower capital expenditure level compared to 2014, anticipating a tempering of economic activity due to recent lower oil prices.

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The company, along with a partner, expects to build a 345-kV transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The company’s share of the cost is estimated at approximately $170 million. The project is a Midcontinent Independent System Operator multivalue project. A route application was filed in August 2013 with the state of South Dakota and in October 2013 with the state of North Dakota. A route permit was approved July 10 in North Dakota and Aug. 13 in South Dakota. The South Dakota route permit was appealed and a district court ruled in favor of the project. The district court decision has been appealed to the South Dakota Supreme Court. The company continues to expect the project to be completed in 2019.

•	The company is pursuing additional generation projects to meet projected capacity requirements, including 19 MW of natural gas generation at the Lewis & Clark Station to be in service later this year.

•	The company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with company- and customer-owned pipelines designed to serve existing facilities utilizing fuel oil or propane, and to serve new customers.

•	The company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.

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The company, in conjunction with Calumet Specialty Products Partners, L.P., formed Dakota Prairie Refining, LLC, to develop, build and operate a 20,000-barrel-per-day refinery in southwestern North Dakota. Construction began on the facility in late March 2013 and operations have commenced. The facility has begun producing diesel fuel and is expected to begin sales of diesel as the plant ramps up during May. The refinery processes Bakken crude into diesel, which is marketed within the Bakken region. Other byproducts, naphtha and atmospheric tower bottoms, are being transported to other areas. The total project cost is estimated to be approximately $425 million to $435 million. EBITDA for the first full year of operation is projected to be in the range of $60 million to $80 million, to be shared equally with Calumet.

•	The company is evaluating the construction of a second 20,000-barrel-per-day refinery to be located near Minot, North Dakota, in the Bakken region. The company expects economic evaluation of this project to continue through much of 2015.

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The company continues work on acquiring easements as well as filing its application for its planned Wind Ridge Pipeline project, a 95-mile natural gas pipeline designed to deliver approximately 90 million cubic feet per day to an announced fertilizer plant near Spiritwood, North Dakota. The project is estimated to cost approximately $120 million, with an in-service date in 2017. There is an opportunity to expand this pipeline's capacity to serve other customers in eastern North Dakota.

•	The company has entered into an agreement with an anchor shipper to construct a pipeline to connect the Demicks Lake gas processing plant in northwestern North Dakota to deliver natural gas into a new interconnect with the Northern Border Pipeline. Project costs are estimated to be $50 million to $60 million.

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The company continues to pursue new growth opportunities and expansion of existing facilities and services offered to customers. The company expects energy development to continue to grow long term within its geographic region, most notably in the Bakken area, where the company owns an extensive natural gas pipeline system. The company plans to invest $1.1 billion of capital related to ongoing energy and industrial development over the next five years.

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The construction materials approximate work backlog as of March 31 was $664 million, compared to $653 million a year ago. Private work represents 10 percent of construction backlog and public work represents 90 percent of backlog. The March 31 approximate backlog at construction services was $321 million, compared to $397 million a year ago. The backlogs include a variety of projects such as highway grading, paving and underground projects, airports, bridge work, subdivisions, substation and line construction, solar and other commercial, institutional and industrial projects including petrochemical work.

•	Projected revenues included in the company's 2015 earnings guidance are in the range of $1.7 billion to $1.9 billion for construction materials and $1.1 billion to $1.3 billion for construction services.

•	The company anticipates margins in 2015 to be higher at construction materials and slightly lower at construction services compared to 2014 margins.

•	The company continues to pursue opportunities for expansion in energy projects such as petrochemical, transmission, substations, utility services, solar, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expanding into new markets.

•	As the country's fifth-largest sand and gravel producer, the company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

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•	The company intends to market and sell its exploration and production company and although an actual sale date is unknown, for forecasting purposes the company is assuming a sale transaction after 2015.

•	During 2015, the company plans to continue to focus on maximizing the value of the company to market it for sale, including focusing on lowering its cost structure beyond the 25 percent general and administrative cost reduction already in place.

•	The company expects to spend approximately $108 million in gross capital expenditures in 2015, operating within projected cash flows. The company currently has no rigs drilling on its operated properties and anticipates commencing drilling in the second half of this year.

•	Key activities for 2015 include:

◦	Commissioning and startup of the gas gathering and processing facilities in the Paradox Basin.

◦	Fracture stimulate two wells and drill new wells in the Paradox Basin.

◦	Completion of a backlog of wells in the non-operated Powder River Basin.

◦	Completion of 2014 activity carryover in the Bakken.

◦	Drilling of additional horizontal wells in East Texas is currently not planned in this low natural gas price environment.

•	Operational updates:

◦	The Cane Creek Unit 28-3 well (100 percent working interest) completed in mid-December and slowly ramped up to about 600 BOPD, has continued to flow 600 BOPD on an 11/64ths inch choke at a current flowing tubing pressure of approximately 1,790 psi.

◦	Commissioning of the Blues Hills natural gas plant in the Paradox field began in late January with first gas sales occurring March 10. Commissioning of the plant is expected to be completed by the end of May.

◦	Per unit lease operating costs in the first quarter of 2015 were 15 percent lower than costs for the same time period in 2014 after adjusting for 2014 asset divestments. Lower operating costs have been achieved through reductions in costs of services as well as optimization of production operations.

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The company is projecting a 2015 net loss of approximately $30 million to $40 million excluding the first quarter ceiling test impairment and any potential future ceiling test impairments. Annual oil production is expected to decline approximately 27 percent in 2015 primarily due to 2014 divestments in the Bakken and limited oil-related investments in 2015. Annual natural gas and natural gas liquids volumes are estimated to decrease 10 percent and 27 percent, respectively, in 2015, primarily the result of 2014 asset divestments in South Texas. The December 2015 oil production rate is estimated to decrease 20 percent compared to December 2014, while natural gas and natural gas liquids rates are estimated to decrease 5 percent and 3 percent, respectively. The company is assuming average NYMEX index prices for May through December 2015 of $54.50 per barrel of crude oil, $2.83 per Mcf of natural gas and $21.94 per barrel of natural gas liquids.

•	Derivatives in place as of May 3 include:

◦	For April through June 2015, 7,000 BOPD of swaps at a weighted average price of $53.21, and a 1,500 BOPD costless collar with a floor/ceiling of $50.00/$57.50.

◦	For July through September 2015, 6,000 BOPD at a weighted average price of $55.78.

◦	For October through December 2015, 6,000 BOPD at a weighted average price of $58.61.

◦	For April through December 2015, 10,000 MMBtu of natural gas per day at a weighted average price of $4.28.

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•	Exploration and production loss of $328.9 million and earnings of $20.9 million in 2015 and 2014, respectively.

•	Exploration and production loss of $253.1 million.

•	A multiemployer pension plan withdrawal liability of $8.4 million after tax recorded in fourth quarter 2014.

•	Exploration and production earnings of $95.1 million.

•	A net benefit related to natural gas gathering operations litigation of $1.5 million after tax.

•	Natural gas gathering asset impairment of $9.0 million after tax.

•	The company’s exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, that are subject to various external influences that cannot be controlled.

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Actual quantities of recoverable oil, natural gas liquids and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in estimates of proved reserve quantities or other factors including low oil and natural gas prices, could result in future noncash write-downs of the company's oil and natural gas properties.

•	The regulatory approval, permitting, construction, startup and/or operation of power generation facilities may involve unanticipated events or delays that could negatively impact the company’s business and its results of operations and cash flows.

•	The operation of Dakota Prairie refinery may involve unanticipated events or delays that could negatively impact the company's business and its results of operations and cash flows.

•	Economic volatility affects the company’s operations, as well as the demand for its products and services and the value of its investments and investment returns including its pension and other postretirement benefit plans, and may have a negative impact on the company’s future revenues and cash flows.

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The company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the company’s control. If the company is unable to obtain economic financing in the future, the company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the company may otherwise rely on for future growth could be impaired. As a result, the market value of the company’s common stock may be adversely affected. If the company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.

•	The company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the company’s customers and counterparties.

•	The backlogs at the company’s construction materials and contracting and construction services businesses are subject to delay or cancellation and may not be realized.

•	The company’s operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the company to environmental liabilities.

•	Initiatives to reduce greenhouse gas emissions could adversely impact the company’s operations.

•	The company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the company.

•	Weather conditions can adversely affect the company’s operations, and revenues and cash flows.

•	Competition is increasing in all of the company’s businesses.

•	The company could be subject to limitations on its ability to pay dividends.

•	An increase in costs related to obligations under multiemployer pension plans could have a material negative effect on the company’s results of operations and cash flows.

•	The company's operations may be negatively impacted by cyber attacks or acts of terrorism.

•	While the company plans to market and sell its exploration and production business, there is no assurance that it will be successful.

•	Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include:

◦	Acquisition, disposal and impairments of assets or facilities.

◦	Changes in operation, performance and construction of plant facilities or other assets.

◦	Changes in present or prospective generation.

◦	The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.

◦	The availability of economic expansion or development opportunities.

◦	Population growth rates and demographic patterns.

◦	Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services.

◦	The cyclical nature of large construction projects at certain operations.

◦	Changes in tax rates or policies.

◦	Unanticipated project delays or changes in project costs, including related energy costs.

◦	Unanticipated changes in operating expenses or capital expenditures.

◦	Labor negotiations or disputes.

◦	Inability of the various contract counterparties to meet their contractual obligations.

◦	Changes in accounting principles and/or the application of such principles to the company.

◦	Changes in technology.

◦	Changes in legal or regulatory proceedings.

◦	The ability to effectively integrate the operations and the internal controls of acquired companies.

◦	The ability to attract and retain skilled labor and key personnel.

◦	Increases in employee and retiree benefit costs and funding requirements.

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