Edgar Filing: BLACK HILLS CORP /SD/

BKH 10K/A 12 2014

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K/A

(Amendment No. 1)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014



o	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 001-31303

BLACK HILLS CORPORATION



Incorporated in South Dakota	625 Ninth Street	IRS Identification Number
	Rapid City, South Dakota 57701	46-0458824
Registrant’s telephone number, including area code (605) 721-1700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common stock of $1.00 par value		New York Stock Exchange

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 o

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 o 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 o

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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

At June 30, 2014 $2,696,775,649

Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.



Class	Outstanding at January 31, 2015
Common stock, $1.00 par value	44,676,072	shares

Documents Incorporated by Reference

Portions of the Registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2015 Annual Meeting of Stockholders to be held on April 28, 2015, are incorporated by reference in Part III of this Form 10-K.

Explanatory Note

This Amendment No. 1 (this “Amendment”) amends the Annual Report on Form 10-K for the annual period ended December 31, 2014 originally filed by Black Hills Corporation on February 25, 2015 (the “Original Filing”).

In preparing our consolidated financial statements for the quarter ended June 30, 2015, we identified immaterial errors that impacted our previously issued consolidated financial statements. The prior period errors originated in the year ended December 31, 2008 and related to our oil and gas full cost ceiling impairment calculation to determine whether the net book value of the our oil and gas properties exceeded the ceiling. Specifically, the errors related to evaluating and correctly accounting for the treatment of tax related amounts associated with the calculation. The original errors identified caused an understatement of 2008, 2009, 2012 and Q1 2015 noncash ceiling test impairment calculations, which resulted in an overstatement of depletion expense from 2009 through March 31, 2015, and an understatement of the 2012 gain on sale of oil and gas properties, further described in Note 1 to the consolidated financial statements filed in this Annual Report on Form 10-K/A.

As a result of these immaterial errors, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we re-evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, using the criteria in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this re-evaluation, we have determined that a material weakness in internal control over financial reporting relating to our oil and gas full-cost ceiling, non-cash impairment calculation existed as of December 31, 2014. As a result, we have revised Management’s Report on Internal Control Over Financial Reporting for the year ended December 31, 2014, included herein.

Notwithstanding the material weakness described above, we have concluded that our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014 as previously filed with the Securities and Exchange Commission (“SEC”), are fairly stated in all material respects in accordance with generally accepted accounting principles in the United States of America for each of the periods presented and that they may still be relied upon. Given this Amendment, we have revised our previously issued consolidated financial statements for the effects of immaterial errors included in this Annual Report on Form 10-K/A for the year ended December 31, 2014.

The following items have been amended as a result of the revision of Management’s Report on Internal Control Over Financial Reporting and to correct immaterial errors:


•	Item 6 - Selected Financial Data


•	Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations


•	Item 8 - Financial Statements and Supplementary Data


•	Item 9A - Controls and Procedures


•	Item 15 - Exhibits

In accordance with applicable SEC rules, this Annual Report on Form 10-K/A includes certifications from our Chief Executive Officer and Chief Financial Officer dated as of the date of this filing.

Except for the impact of the items discussed above, no other changes have been made to the Original Filing. This Annual Report on Form 10-K/A continues to describe conditions as of the date of the Original Filing, and the disclosures contained herein have not been updated to reflect events, results or developments that have occurred after the Original Filing date, or to modify or update those disclosures affected by subsequent events.

Concurrently with the filing of this Annual Report on Form 10-K/A, we are also filing an amendment to our Form 10-Q for the quarterly period ended March 31, 2015.

Website Access to Reports

The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document.

Forward-Looking Information

This Form 10-K/A contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in our Original Filing and this Form 10-K/A, including statements contained within Item 1A - Risk Factors.

PART II


ITEM 6.	SELECTED FINANCIAL DATA



Years Ended December 31,	2014			2013				2012				2011				2010
(dollars in thousands, except per share amounts)

Total Assets	$	4,245,902		$	3,837,936			$	3,688,335			$	4,053,216			$	3,631,412

Property, Plant and Equipment
Total property, plant and equipment	$	4,563,400		$	4,259,445			$	3,930,772			$	3,724,016			$	3,353,509
Accumulated depreciation and depletion	$	(1,357,929	)	$	(1,306,390	)		$	(1,229,159	)		$	(1,008,307	)		$	(941,872	)

Capital Expenditures	$	391,267		$	379,534			$	347,980			$	431,707			$	496,990

Capitalization
Current maturities of long-term debt	$	275,000		$	—			$	103,973			$	2,473			$	5,181
Notes payable	75,000			82,500				277,000				345,000				249,000
Long-term debt, net of current maturities	1,267,589			1,396,948				938,877				1,280,409				1,186,050
Common stock equity	1,353,884			1,283,500				1,205,800				1,161,715				1,048,642
Total capitalization	$	2,971,473		$	2,762,948			$	2,525,650			$	2,789,597			$	2,488,873

Capitalization Ratios
Short-term debt, including current maturities	12		%	3		%		15		%		12		%		10		%
Long-term debt, net of current maturities	42		%	51		%		37		%		46		%		48		%
Common stock equity	46		%	46		%		48		%		42		%		42		%
Total	100		%	100		%		100		%		100		%		100		%

Total Operating Revenues	$	1,393,570		$	1,275,852			$	1,173,884			$	1,272,188			$	1,219,691

Net Income Available for Common Stock
Utilities	$	101,421		$	84,841			$	79,588			$	81,860			$	74,563
Non-regulated Energy	30,443			20,864			(1)	45,637			(1)	4,875				14,410
Corporate and intersegment eliminations	(975		)	12,602			(2)	(15,808		)	(2)	(42,361		)	(2)	(21,611		)	(2)
Income (loss) from continuing operations	130,889			118,307				109,417				44,374				67,362
Income (loss) from discontinued operations, net of tax ⁽³⁾	—			(884		)		(6,977		)		9,365				5,544
Net income available for common stock	$	130,889		$	117,423			$	102,440			$	53,739			$	72,906

SELECTED FINANCIAL DATA continued



Years Ended December 31,	2014		2013			2012			2011		2010
(dollars in thousands, except per share amounts)

Dividends Paid on Common Stock	$	69,636	$	67,587		$	65,262		$	59,202	$	56,467

Common Stock Data⁽⁴⁾ (in thousands)
Shares outstanding, average basic	44,394		44,163			43,820			39,864		38,916
Shares outstanding, average diluted	44,598		44,419			44,073			40,081		39,091
Shares outstanding, end of year	44,672		44,499			44,206			43,925		39,269

Earnings (Loss) Per Share of Common Stock (in dollars) ⁽⁴⁾
Basic earnings (loss) per average share -
Continuing operations	$	2.95	$	2.68		$	2.50		$	1.11	$	1.73
Discontinued operations	—		(0.02		)	(0.16		)	0.24		0.14
Total	$	2.95	$	2.66		$	2.34		$	1.35	$	1.87
Diluted earnings (loss) per average share -
Continuing operations	$	2.93	$	2.66		$	2.48		$	1.11	$	1.73
Discontinued operations	—		(0.02		)	(0.16		)	0.23		0.14
Non-controlling interest	—		—			—			—		—
Total	$	2.93	$	2.64		$	2.32		$	1.34	$	1.87

Dividends Declared per Share	$	1.56	$	1.52		$	1.48		$	1.46	$	1.44




Book Value Per Share, End of Year	$	30.31		$	28.84		$	27.28		$	26.45		$	26.70

Return on Average Common Stock Equity (full year)	9.9		%	9.4		%	8.7		%	4.9		%	6.8		%

SELECTED FINANCIAL DATA continued



Years ended December 31,	2014	2013	2012	2011	2010
Operating Statistics:
Generating capacity (MW):
Electric Utilities (owned generation)	841	790	859	865	687
Electric Utilities (purchased capacity)	210	150	150	450	440
Power Generation (owned generation)	269	309	309	309	120
Total generating capacity	1,320	1,249	1,318	1,624	1,247

Electric Utilities:
MWh sold:
Retail electric	4,775,808	4,642,254	4,598,080	4,590,800	4,532,191
Contracted wholesale	340,871	357,193	340,036	349,520	468,782
Wholesale off-system	1,118,641	1,456,762	1,652,949	1,788,005	1,749,524
Total MWh sold	6,235,320	6,456,209	6,591,065	6,728,325	6,750,497

Gas Utilities:⁽⁵⁾
Gas sold (Dth)	60,323,416	59,097,493	47,358,505	55,764,154	55,265,630
Transport volumes (Dth)	67,463,143	63,821,546	60,480,822	59,216,132	59,879,450

Power Generation Segment:
MWh Sold	1,760,160	1,564,789	1,304,637	556,577	519,057
MWh Purchased	38,237	5,481	8,011	402	27,734

Oil and Gas Segment:
Oil and gas production sold (MMcfe)	9,986	9,529	12,544	11,762	11,300
Oil and gas reserves (MMcfe)⁽¹⁾	101,416	86,713	80,683	133,242	131,096

Coal Mining Segment:
Tons of coal sold (thousands of tons)⁽⁶⁾	4,317	4,285	4,246	5,692	5,931
Coal reserves (thousands of tons)	208,231	212,595	232,265	256,170	261,860

____________________________________

(1)

2013 includes $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs. 2012 includes a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $32 million offset by an after-tax gain on sale of $49 million related to our Williston Basin assets. Reserves reflect the sale of the Williston Basin assets (see Notes 12 and 21 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K/A).

(2)

2011 and 2010 include a $27 million and $9.9 million non-cash after-tax unrealized mark-to-market loss, respectively, related to certain interest rate swaps; while 2013 and 2012 include a $20 million and $1.2 million non-cash after-tax unrealized mark-to-market gain, respectively, related to certain interest rate swaps. 2013 also includes $7.6 million after-tax expense for a make-whole premium, write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, while 2012 includes an after-tax make-whole provision of $4.6 million for early redemption of our $225 million notes.


(3)	Discontinued operations include post-closing adjustments and operations relating to our Energy Marketing segment in 2013, 2012, 2011 and 2010.


(4)	During November 2011, we issued 4.4 million shares of common stock, which diluted our earnings per share in subsequent periods.


(5)	Excludes Cheyenne Light.


(6)	Tons of coal decreased in 2012 due to the expiration of an unprofitable train load-out contract.



	December 31, 2014						December 31, 2013
(in thousands, except per share and percentages)	As Reported		Adjustments		As Revised		As Reported		Adjustments		As Revised

Net Income Available for Common Stock
Non-regulated Energy (in thousands)	$	28,335	$	2,108	$	30,443	$	18,403	$	2,461	$	20,864



	December 31, 2012
(in thousands, except per share and percentages)	As Reported			Adjustments			As Revised

Total Assets	$	3,729,471		$	(41,136	)	$	3,688,335

Property, Plant and Equipment
Accumulated depreciation and depletion	$	(1,188,023	)	$	(41,136	)	$	(1,229,159	)

Common stock equity	$	1,232,509		$	(26,709	)	$	1,205,800

Net Income Available for Common Stock
Non-regulated Energy	$	24,725		$	20,912		$	45,637



	December 31, 2011									December 31, 2010
(in thousands, except per share and percentages)	As Reported			Adjustments			As Revised			As Reported			Adjustments			As Revised

Total Assets	$	4,127,083		$	(73,867	)	$	4,053,216		$	3,711,509		$	(80,097	)	$	3,631,412

Property, Plant and Equipment
Accumulated depreciation and depletion	$	(934,441	)	$	(73,866	)	$	(1,008,307	)	$	(861,775	)	$	(80,097	)	$	(941,872	)

Common stock equity	$	1,209,336		$	(47,621	)	$	1,161,715		$	1,100,270		$	(51,628	)	$	1,048,642

Net Income Available for Common Stock
Non-regulated Energy	$	866		$	4,009		$	4,875		$	10,189		$	4,221		$	14,410

Earnings (Loss) Per Share of Common Stock
Basic earnings (loss) per share per average share -
Continuing Operations	$	1.01		$	0.10		$	1.11		$	1.62		$	0.11		$	1.73
Discontinued Operations	$	0.24		$	—		$	0.24		$	0.14		$	—		$	0.14
Total	$	1.25		$	0.10		$	1.35		$	1.76		$	0.11		$	1.87
Diluted earnings (loss) per share per average share -
Continuing Operations	$	1.01		$	0.10		$	1.11		$	1.62		$	0.11		$	1.73
Discontinued Operations	$	0.23		$	—		$	0.23		$	0.14		$	—		$	0.14
Total	$	1.24		$	0.10		$	1.34		$	1.76		$	0.11		$	1.87

For additional information on our business segments see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note 4 to the Consolidated Financial Statements in this Annual Report on Form 10-K/A.


ITEMS 7 &	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS


and 7A.	OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET

RISK

We are a customer-focused integrated energy company operating principally in the United States with two major business groups - Utilities and Non-regulated Energy. We report our business groups in the following financial segments:



Business Group	Financial Segment

Utilities	Electric Utilities
	Gas Utilities
Non-regulated Energy	Power Generation
	Coal Mining
	Oil and Gas

Overview: Our customer focus provides opportunities to expand our business by constructing additional rate base assets to serve our utility customers and expanding our non-regulated energy products and services to our wholesale customers.

The diversity of our energy operations reduces reliance on any single business segment to achieve our strategic objectives. Our emphasis on our utility business with diverse geography and fuel mix, combined with a conservative approach to our non-regulated energy operations, mitigates our overall corporate risk and enhances our ability to earn stronger returns for shareholders over the long-term. Our long-term strategy focuses on growing both our utility and non-regulated energy businesses, primarily by increasing our customer base and providing superior service.

Our objective is to be best-in-class relative to certain operational performance metrics, such as safety, power plant availability, electric and gas system reliability, efficiency, customer service and cost management. Our notable operational performance metrics for 2014 include:


•	Our three electric utilities achieved 1^st quartile reliability ranking with 74 customer minutes of outage time (SAIDI) in 2014 compared to industry averages (IEEE 2013 1^st quartile is less than 85 minutes);


•	Our JD Power Customer Satisfaction Survey indicated our Electric and Gas Utilities were favorable to our peers in the Midwest;


•	Our power generation fleet achieved a forced outage factor of 2.7% for coal-fired plants, 2.8% for natural gas plants in 2014 and 0.1% for diesel plants, compared to an industry average^* of 3.5%, 4.6% and 1.7%, respectively (^*NERC GADS 2013 data);


•	Our power generation fleet availability was 94% for coal-fired plants, 95% for gas-fired plants, 96% for diesel-fired plants and 99% for wind generation in 2014 while the industry averages^were 90%, 90%, 96% and 96%, respectively (^NERC GADS Data Base, 2013 most recent industry information);


•	Our safety TCIR of 2.0 compares well to an industry average of 2.8^* and our DART rate of 1.1 compares to an industry average of 1.4⁺ (⁺Most recent industry averages are 2012);

•

Our OSHA TCIR rate during construction of our generating facilities is also significantly better than industry average with a TCIR rate of 2 during the construction of the Wygen III coal-fired plant compared to an industry average of 5.1 for coal-fired plants, 1.3 during the construction of the Pueblo Airport Generating Station natural-gas fired plant compared to an industry average of 4.4 for natural-gas fired plants, 0 during construction of the Busch Ranch wind farm compared to an industry average of 4.4 for wind construction and 0 during the construction of the Cheyenne Prairie Generating Station natural-gas fired plant compared to an industry average of 2.1 for fossil fuel electric power generation; and


•	Our coal mine completed three years with favorable MSHA safety results compared to other mines located in the Powder River Basin and received an award from the State of Wyoming for five years without a lost time accident.

The electric utility industry is facing requirements to upgrade aging infrastructure, deploy smart grid technology and comply with new state and federal environmental regulations and renewable portfolio standards. Increased energy efficiency, and smart grid technologies suppress demand in many areas of the United States. These competing considerations present challenges to energy companies’ approach of balancing capital spending and obtaining satisfactory rate recovery on investments.

State regulatory commissions have lowered authorized returns and implemented other regulatory mechanisms for cost recovery due to the slow-growing economy and concerns that utility rate increases may further harm local economies. The average awarded return on equity for investor-owned utilities over the past year has been averaging around 10%. The average regulatory lag is less than 12 months, according to the Edison Electric Institute. Falling interest rates account for much of the lower rates of return, along with actions by state commissions to moderate rate increases during a period of economic recovery.

In our gas and electric utilities’ service territories, we will continue to work with regulators to ensure we meet our obligations to serve projected customer demand and to comply with environmental mandates by constructing the infrastructure necessary to provide safe, reliable energy. By maintaining our high customer service and reliability standards in a cost-efficient manner, our goal is to secure appropriate rate recovery that provides fair economic returns on our utility investments.

The proliferation of domestic crude oil and natural gas production from shale plays in recent years has provided the domestic market an abundant new supply of both commodities, which has decreased the dependence on foreign resources of these commodities. The increased worldwide supply of crude oil caused WTI prices to decline from June 2014 highs of over $105 per Bbl, to January 2015 lows in the mid-$40s per Bbl. Natural gas prices have fallen from NYMEX prices exceeding $8.00 per MMbtu in February 2014 to below $3.00 per MMbtu in January 2015. Crude oil and natural gas prices are very difficult to predict. We will continue to evaluate the economics for oil or gas projects and investments to exceed our cost of capital. We strive to maintain strong relationships with mineral owners, landowners and regulatory authorities. As prudent, we will continue to grow and develop our existing inventory of crude oil and natural gas reserves. We intend to focus our near-term efforts on proving up the substantial Mancos shale gas potential of our Piceance Basin properties. Given increased regulatory emphasis on wind and solar power resources and environmental regulations and legislation that will limit construction of new coal-fired power plants, we believe that natural gas will be the fuel of choice for power generation. Additional gas-fired peaking resources will also be required to provide critical back-up for renewable technologies.

Currently approximately 40% of electricity generated in the United States is from coal-fired power plants. It will take significant time and expense before this generation can be replaced with alternative technologies. As a result, coal-fired resources will remain a necessary component of the nation’s electric supply for the foreseeable future. The current regulatory climate, combined with the EPA's proposed and expected GHG regulations, have limited construction of new conventional coal-fired power plants, but, if technologies such as carbon capture and sequestration become more proven and less expensive, they could provide for the long-term economic use of coal. We have investigated and will continue to investigate the possible deployment of these technologies at our mine site in Wyoming.

We have expertise in permitting, constructing and operating power generation facilities. These skills, combined with our understanding of electric resource planning and regulatory procedures, provide a significant opportunity for us to add long-term shareholder value. We intend to grow our non-regulated power generation business by continuing to focus on long-term contractual relationships with our affiliates and other load-serving utilities.

Key Elements of our Business Strategy

Provide stable long-term rates for customers and increase earnings by efficiently planning, constructing and operating rate-base power generation facilities needed to serve our electric utilities. Our Company began as a vertically-integrated electric utility. This business model remains a core strength and strategy today, as we invest in and operate efficient power generation resources to cost effectively transmit and distribute electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.

We have a competitive power production strategy focused on low cost construction and operation of our generating facilities. Access to our own coal and third-party natural gas reserves allows us to be competitive as a power generator. Low production costs can result from a variety of factors including low fuel costs, efficiency in converting fuel into energy and low per unit operation and maintenance costs. We leverage our mine-mouth coal-fired generating capacity which strengthens our position as a low-cost producer by eliminating fuel transportation costs which often represent the largest component of the delivered cost of coal for many other utilities. In addition, we typically operate our plants with high levels of availability, compared to industry benchmarks. We aggressively manage each of these factors with the goal of achieving low production costs.

Rate-base generation assets offer several advantages including:


•	Since the generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run, than if the power was purchased from the open market through wholesale contracts that are re-priced over time;


•	Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;


•	Investors are provided a long-term, reasonable, stable return on their investment; and


•	The lower risk profile of rate based generation assets may enhance credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

Our actions to provide power at reasonable rates to our customers was exemplified in our successful request to secure the construction financing riders in Wyoming and South Dakota during the construction of Cheyenne Prairie. These riders reduced the total cost of the plant ultimately passed along to our customers while we constructed this plant to accommodate growth and replace plants that were closed prematurely due to environmental regulations.

Provide stable long-term rates for customers and increase earnings by efficiently planning and implementing a cost of service gas program to serve our electric and natural gas utilities. To further enhance our vertically integrated utility business model, we are evaluating the implementation of a program supporting our natural gas and electric utilities that can provide longer-term rate stability for our customers by enhancing our current gas supply portfolio through the addition of utility or affiliate-owned gas production and reserves. In addition to providing our customers the benefits associated with more predictable long-term commodity prices, it also provides increased earnings opportunity for our shareholders. We are discussing the concept with state regulatory commissioners, staff and consumer advocates. Prior to proceeding, we will need to obtain regulatory approval from our state utility commissions for the program. Several utilities have cost of service gas programs in place in various states, including both Wyoming and Montana.

We have a competitive advantage related to cost of service gas in that our existing non-regulated oil and gas subsidiary could assist in drilling/acquiring and operating the gas reserves required to meet the needs of our electric and gas utilities.

Expand utility operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages. For more than 130 years we have provided reliable utility services, delivering quality and value to our customers. Utility operations contribute substantially to the stability of our long-term cash flows, earnings and dividend policy. Our tradition of accomplishment supports efforts to expand our utility operations into other markets, most likely in areas that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system reliability, superior customer service, community involvement and a relationship-based approach to regulatory matters. Utility operations also enhance other important business development opportunities, including gas transmission pipelines and storage infrastructure, which could promote other non-regulated energy operations.

We have and will continue to pursue the purchase of not only large utility properties, but also smaller, private or municipal utility systems, which can be easily integrated into our operations. We purchased several small natural gas distribution systems in Kansas, Iowa and Wyoming in the past several years. We have a scalable platform of systems and processes, which simplifies the integration of our utility acquisitions. Merger and acquisition activity has continued in the utility industry and we expect to consider such opportunities if they advance our long-term strategy and add shareholder value.

Build and maintain strong relationships with wholesale power customers of both our utilities and non-regulated power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be a primary provider of electricity to wholesale utility customers, who will continue to need products, such as capacity, in order to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns over the long term than we could by selling energy into more volatile spot markets. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint owners in two of our power plants, Wygen I and Wygen III.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating and remaining mindful of customer rate impacts. The energy and utility industries face tremendous uncertainty related to the potential impact of legislation and regulation intended to reduce GHG emissions and increase the use of renewable and other alternative energy sources. To date, many states have enacted and others are considering some form of mandatory renewable energy standard, requiring utilities to meet certain thresholds of renewable energy generation. Some states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both renewable energy standards and GHG emission reductions is also under consideration.

Mandates for the use of renewable energy or the reduction of GHG emissions will likely produce substantial increases in the prices for electricity and natural gas. At the same time, as a regulated utility we are responsible for providing safe, reasonably priced, reliable sources of energy to our customers. As a result, we employ a customer-centered strategy for complying with renewable energy standards and GHG emission regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.

•

Colorado legislative mandates apply to our electric utility segment regarding the use of renewable energy. Therefore, we pursue cost-effective initiatives that allow us to meet our renewable energy requirements. Where permitted, we seek to construct renewable generation resources as rate base assets, which helps mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the Busch Ranch Wind site, a 29 MW wind turbine project, was completed in the fourth quarter of 2012, as part of our plan to meet Colorado’s Renewable Energy Standard. This site also has expansion potential;

•

In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future. For example, under two 20-year PPAs we purchase a total of 60 MW of wind energy from wind farms located near Cheyenne, Wyoming for use at Black Hills Power and Cheyenne Light; and


•	In all states in which we conduct electric utility operations, we are exploring other cost-effective potential biomass, solar and wind energy projects, particularly wind generation sites located near our utility service territories.

Increase the value of our oil and gas properties by prudently growing our reserves and increasing our production of natural gas and crude oil. Our strategy is to cost-effectively grow our reserves and increase our production of natural gas and crude oil through both organic growth and acquisitions. While consistent growth remains our objective, we emphasize managing for value creation over managing for growth as follows:


•	Perform detailed reservoir analysis and apply proven technologies to our existing assets to maximize value;


•	Participate in a limited number of selective and meaningful exploration prospects;

•

Focus primarily on the Rocky Mountain region, where we can more easily integrate new opportunities with our existing crude oil and natural gas operations as well as our power generation activities. Specifically, we intend to focus our near term efforts on fully developing the substantial shale gas potential of our San Juan and Piceance Basin properties and participating in select oil exploration prospects with substantial upside opportunities;


•	Support the future capital requirements of our drilling program by stabilizing cash flows with a hedging program that mitigates commodity price risk for up to three years of future production; and


•	Enhance our crude oil and natural gas production activities with the construction or acquisition of mid-stream gathering, compression and treating facilities in a manner that maximizes the economic value of our operations.

Selectively grow our non-regulated power generation business in targeted regional markets by developing assets and selling most of the capacity and energy production through mid- and long-term contracts primarily to load-serving utilities. While much of our recent power plant development has been for our regulated utilities, we seek to expand our non-regulated power generation business by developing and operating power plants in regional markets based on prevailing supply and demand fundamentals, in a manner that complements our existing fuel assets and marketing capabilities. We seek to grow this business through the development of new power generation facilities and disciplined acquisitions primarily in the western region, where we believe our detailed knowledge of market and electric transmission fundamentals provides us a competitive advantage and, consequently, increases our ability to earn attractive returns. We prioritize small-scale facilities that serve incremental growth or provide critical back up to renewable resources and are typically easier to permit and construct than large-scale generation projects.

Most of the energy and capacity from our non-regulated power facilities is sold under mid- and long-term contracts. When possible, we structure long-term contracts as tolling arrangements, whereby the contract counterparty assumes the fuel risk. Going forward, we will continue to focus on selling a majority of our non-regulated capacity and energy primarily to load-serving utilities under long-term agreements that have been reviewed or approved by state utility commissions. An example of this strategy is the 200 MW of combined-cycle gas-fired generation constructed by our non-regulated power generation subsidiary to serve our Colorado Electric utility subsidiary. The plant commenced operations on January 1, 2012, under a 20-year tolling agreement.

Diligently manage the credit, price and operational risks inherent in buying and selling energy commodities. All of our operations require effective management of counterparty credit risk. We mitigate this risk by conducting business with a diverse group of creditworthy counterparties. In certain cases where creditworthiness merits security, we require prepayment, secured letters of credit or other forms of financial collateral. We establish counterparty credit limits and employ continuous credit monitoring, with regular review of compliance under our credit policy by our Executive Risk Committee. Our oil and gas and power generation operations require effective management of price and operational risks related to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we implemented risk management policies and procedures. Our oversight committees monitor compliance with these policies.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. Access to capital has been and will continue to be critical to our success. We have demonstrated our ability to access the debt and equity markets, resulting in sufficient liquidity. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent business growth. Our access to adequate and cost-effective financing depends upon our ability to maintain our investment-grade issuer credit rating.

Moody’s and Fitch each upgraded our corporate credit rating during 2014, which enhanced our capacity to extend our revolving credit facility, and place permanent financing for Cheyenne Prairie through the sale of $160 million of first mortgage bonds in a private placement at favorable terms.

Prospective Information

We expect to generate long-term growth through the expansion of integrated and diverse energy operations. Sustained growth requires continued capital deployment. Our diversified energy portfolio with an emphasis on regulated utilities provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from major capital investments at our existing business segments. During 2014, we put permanent financing in place for Cheyenne Prairie and during 2013, we refinanced much of our highest cost debt on favorable terms. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan.

Utilities Group

Electric Utilities

On October 1, 2014, Black Hills Power and Cheyenne Light placed into commercial service their jointly-owned Cheyenne Prairie generating station, a 132 MW generating facility located in Cheyenne, Wyoming. Cheyenne Prairie was constructed on time and on budget. Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie. Cheyenne Light and Black Hills Power received approval for increased rates in Wyoming effective October 1, 2014. Black Hills Power also implemented interim rates in South Dakota on October 1, 2014. Hearings for the South Dakota rate case were held on January 27-28, 2015 and the commission’s final decision is expected in first quarter 2015.

Residential MWh sold decreased in 2014 due to milder weather resulting from lower cooling degree days. Industrial loads increased primarily at Cheyenne Light and Colorado Electric. Cheyenne Light recorded an all-time peak load of 198 MW in July 2014.

BHC continued its efforts to acquire smaller public and municipal gas distribution systems adjacent to our existing service territories. On October 14, 2014, we announced an agreement to acquire Energy West Wyoming, Inc., a Wyoming gas utility, and pipeline assets of Gas Natural, Inc. for $17 million. The gas utility serves approximately 6,700 customers, including service to Cody, Ralston and Meeteetse, Wyoming. The pipeline assets include a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory. In January 2015, Cheyenne Light also closed on the acquisition of assets serving approximately 400 customers in northeast Wyoming.

Cheyenne Light received FERC approval to establish rates for transmission services under their Open Access Transmission Tariff, effective May 3, 2014.

Colorado Electric received a final order from the CPUC approving a CPCN for the retirement of Pueblo Units #5 and #6, effective December 31, 2013.

Pursuant to prior approved resource plans and pending electric rate increase requests, the Electric Utilities engaged in the following regulatory requests related to construction activities:

•

On July 22, 2014, Black Hills Power filed a CPCN with the WPSC to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. Approval by the WPSC is anticipated in the second quarter of 2015. Black Hills Power has received approval from the SDPUC for a permit to construct the line.

•

On May 5, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. On December 23, 2014 the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that our standalone bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.

•

On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million with a return on equity of 9.83% and a capital structure of 49.83% equity and 50.17% debt. The CPUC also authorized the implementation of a rider for a return on capital expenditures for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

Gas Utilities

Weather was colder than normal in the first quarter of 2014, which drove an increase in natural gas sales. Our Gas Utilities invested in our gas distribution network and related technology such as advanced metering infrastructure and mobile data terminals. We continually monitor our investments and costs of operations in all states to determine the appropriateness of additional rate case or other rate filings. As part of our growth strategy, we continue to look for opportunities to purchase municipal and privately-owned gas infrastructure and distribution systems. We acquired a small gas system during 2014 with a total of approximately 70 customers.

Non-regulated Energy Group

Power Generation

Black Hills Wyoming closed the sale of its 40 MW CTII natural gas-fired generating unit to the City of Gillette for approximately $22 million, upon expiration of the PPA with Cheyenne Light in August 2014. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through an economy energy PPA. We recognized approximately $0.5 million of margin under the new economy PPA, which became effective in September 2014. We plan to continue evaluating opportunities to bid on the construction of generation resources, both new and existing, for our affiliate electric utilities and other regional electric utilities for their energy and capacity needs.

Coal Mining

Production from the Coal Mining segment primarily serves mine-mouth generation plants and select regional customers with long-term fuel needs. Total annual production was approximately 4.3 million tons for 2014, which was consistent with 2013. Mining operations moved to an area with lower overburden ratios in 2013, which reduced mining costs, but in 2014, our overburden ratios increased as we mined areas with a higher stripping ratio. Stripping ratios are expected to increase again in 2015 to approximately 1.5 as the areas planned for mining contain higher overburden.

Our strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically our off-site sales have been to consumers within a close proximity to our mine, including off-site sales contracts served by truck. In January 2014, we received State of Wyoming permit approval for Black Hills Power to acquire a stock pile of approximately 75,000 tons of coal near the mine mouth power plants to ensure adequate emergency back-up of coal supply. We continue to pursue new opportunities to market our coal despite limitations inherent to transporting our lower-heat content coal.

Oil and Gas

During 2014, BHEP continued to prove up the value of our existing properties, primarily our Mancos formation shale gas assets in the Piceance and San Juan Basins, while conserving capital and strictly controlling costs. After drilling and completing two Mancos formation exploration wells in the southern Piceance Basin and one exploration well in the San Juan Basin in 2011, the appraisal program was deferred in 2012 due to low natural gas prices. The program continued in 2013 with the drilling of two additional Piceance wells. Three more Piceance wells were drilled in 2014, which will be placed on production during the first quarter of 2015. We plan to continue our efforts in 2015 to prove up the value of our oil and gas properties.

Corporate

Our consolidated interest expense decreased in 2014, primarily due to the refinancing of higher cost debt in 2013 as well as upgrades to our corporate credit ratings by S&P, Moody’s and Fitch during 2014 and 2013. We executed a 10-year $525 million note offering in November 2013 at an interest rate of 4.25%, which we used to repay higher cost debt and settle interest rate swaps. Our interest expense was unfavorably impacted in 2013 by costs related to early retirement of $250 million senior unsecured notes due in 2014 and the settlement of interest rate swaps.

A portion of the proceeds from the $525 million notes in late 2013 were used for the termination of the de-designated interest rate swaps, which did not qualify for “hedge accounting” treatment provided by accounting standards for derivatives and hedges. With the termination of these swaps, our income statement will no longer reflect the volatility associated with fluctuations in the fair value of these swaps caused by interest rate changes.

Results of Operations

Executive Summary and Overview



	For the Years Ended December 31,
	2014			Variance			2013			Variance			2012
	(in thousands)
Revenue
Utilities	$	1,315,079		$	110,082		$	1,204,997		$	123,950		$	1,081,047
Non-regulated Energy	206,030			11,481			194,549			(21,690		)	216,239
Inter-company eliminations	(127,539		)	(3,845		)	(123,694		)	(292		)	(123,402		)
	$	1,393,570		$	117,718		$	1,275,852		$	101,968		$	1,173,884

Income (loss) from continuing operations
Electric Utilities	$	59,552		$	7,418		$	52,134		$	536		$	51,598
Gas Utilities	41,869			9,162			32,707			4,717			27,990
Utilities	101,421			16,580			84,841			5,253			79,588

Power Generation ^(a)	28,516			12,228			16,288			(5,040		)	21,328
Coal Mining	10,452			4,125			6,327			701			5,626
Oil and Gas^(b)	(8,525		)	(6,774		)	(1,751		)	(20,434		)	18,683
Non-regulated Energy	30,443			9,579			20,864			(24,773		)	45,637

Corporate and Eliminations^(c)(d)(e)	(975		)	(13,577		)	12,602			28,410			(15,808		)

Income from continuing operations	130,889			12,582			118,307			8,890			109,417

Income (loss) from discontinued operations, net of tax^(f)	—			884			(884		)	6,093			(6,977		)
Net income (loss)	$	130,889		$	13,466		$	117,423		$	14,983		$	102,440

______________


(a)	Income (loss) from continuing operations in 2013 includes a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.


(b)	Income (loss) from continuing operations in 2012 includes a $32 million non-cash after-tax ceiling test impairment loss and a $49 million after-tax gain on sale of our Williston Basin assets. See Notes 12 and 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K/A.

(c)

Financial results of Enserco, our Energy Marketing segment, have been reclassified as discontinued operations in accordance with GAAP. When preparing this reclassification, certain indirect corporate costs and inter-segment interest expenses previously charged to our Energy Marketing segment could not be reclassified to discontinued operations of $0.6 million for 2012 and accordingly have been presented within Corporate. See Note 21 of the Consolidated Financial Statements in this Annual Report on Form 10-K/A.

(d)

2013 includes a $7.6 million after-tax make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, while 2012 includes a $4.6 million after-tax make-whole premium for the early redemption of our $225 million notes and a $1.0 million write-off of deferred financing costs relating to early renewal of our Revolving Credit Facility.


(e)	2013 and 2012 include a $20 million and a $1.2 million non-cash after-tax mark-to-market gain, respectively, related to certain interest rate swaps.


(f)	Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K/A.

On February 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. Additionally, the following business group and segment information does not include inter-company eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.

2014 Compared to 2013

Income from continuing operations was $131 million, or $2.93 per share, in 2014 compared to $118 million, or $2.66 per share, in 2013. The 2014 Income from continuing operations did not include any expenses, gains, or losses that we believe are not representative of our core operating performance. The 2013 Income from continuing operations includes a $20 million non-cash after-tax mark-to-market gain on certain interest rate swaps, $6.6 million after-tax interest expense related to the early settlement of interest rate swaps and write-off of deferred financing costs associated with the prepayment of Black Hills Wyoming’s project financing and $7.6 million after-tax expense for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes.

Net income was $131 million, or $2.93 per share, in 2014 compared to $117 million, or $2.64 per share, in 2013 and includes the same items described above and losses from our Energy Marketing segment sold in February 2012.

Business Group highlights for 2014 include:

Utilities Group

Highlights of the Utilities Group include the following:

•

Gas Utilities were favorably impacted by colder than normal weather during the first quarter of 2014, which was 14% colder than normal and 7% colder than the first quarter of 2013. This led to an increase in retail natural gas sold and offset unfavorable weather experienced through the remainder of 2014 when compared to 2013. Our service territories reported colder than normal winter weather as measured by heating degree days, compared to the 30-year average, but not as cold as 2013. Heating degree days for the full year in 2014 were 7% colder than normal but 2% less than the same period in 2013.


•	Mild weather was a contributing factor for our Electric Utilities during the year. Weather related demand during the peak summer months was tempered by significantly cooler temperatures within our service territories. Cooling degree days for the full year of 2014 were 29% lower than the same period in the prior year and 12% lower than normal.

•

On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt. The CPUC also authorized the implementation of a rider for a return on capital expenditures for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.


•	On December 16, Kansas Gas received approval from the Kansas Corporation Commission to increase annual base revenue by an estimated $5.2 million, effective Jan. 1, 2015.

•

On October 1, 2014, Black Hills Power and Cheyenne Light placed into commercial service their jointly-owned Cheyenne Prairie generating station. Cheyenne Prairie is a 132 MW, $222 million natural gas-fired generating facility built to serve Black Hills Power and Cheyenne Light customers. Cheyenne Prairie was constructed on time and on budget. Construction financing costs were recovered through construction financing riders.

◦

On October 1, 2014, Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie. Black Hills Power issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 and Cheyenne Light issued $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. Proceeds from Black Hills Power’s bond sale also funded the early redemption of its 5.35%, $12 million pollution control revenue bonds, originally due October 1, 2024.

◦

Black Hills Power and Cheyenne Light each received approval from the WPSC on rate cases associated with Cheyenne Prairie. On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt.

◦

On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Interim rates were implemented on October 1, 2014 when Cheyenne Prairie commenced commercial operations. A final ruling from the SDPUC is expected in the first quarter of 2015.


•	On July 22, 2014, Black Hills Power filed a CPCN with the WPSC to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. Approval by the WPSC is anticipated in the second quarter of 2015.

On June 30, 2014, Black Hills Power filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line, and received approval on November 6, 2014.

•

On May 5, 2014, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. On December 23, 2014 the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that our standalone bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.


•	On April 25, 2014, Cheyenne Light received FERC approval to establish rates for transmission services under their Open Access Transmission Tariff, effective May 3, 2014. The approval includes a return on equity of 10.6% and a capital structure of 54% equity and 46% debt.


•	On March 21, 2014, Black Hills Power retired the Ben French, Neil Simpson I and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. These plants were largely replaced by Black Hills Power’s share of Cheyenne Prairie.


•	On February 25, 2014, the CPUC issued a final order after rehearing, approving a CPCN for the retirement of Pueblo Unit #5 and #6, effective December 31, 2013.


•	BHC continued its efforts to acquire smaller public and municipal gas distribution systems adjacent to our existing service territories.


◦	On January 1, 2015, we closed a $6 million transaction to acquire the natural gas utility assets of MGTC, Inc., a northeast Wyoming system serving more than 400 customers. This system will be operated by and consolidated into the results of Cheyenne Light.

◦

On October 14, 2014, we announced an agreement to acquire Energy West Wyoming, Inc., a Wyoming gas utility, and pipeline assets of Gas Natural, Inc. for $17 million. The gas utility serves approximately 6,700 customers, including service to Cody, Ralston and Meeteetse, Wyoming. The pipeline assets include a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory.


◦	During the first quarter of 2014, we acquired an additional gas system in Kansas, adding approximately 70 customers.

Non-regulated Energy Group


•	Coal Mining completed negotiations on the coal contract price increase with the third-party operator of the Wyodak plant. The new coal price of $18.25 per ton, an increase of approximately $4.75, was effective July 1, 2014.


•	On September 3, 2014, Black Hills Wyoming closed the sale of its 40 MW CTII natural-gas fired generating unit to the City of Gillette, Wyoming for approximately $22 million, upon expiration on August 31, 2014 of the PPA with

Cheyenne Light. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through ancillary agreements, including an operating agreement and an economy energy PPA. The sale resulted in a deferred gain of $4.9 million which Black Hills Wyoming will recognize equally over the twenty-year term of the operating agreement.

•

Our southern Piceance Basin drilling program continued in 2014. During the third quarter, three Mancos Shale wells were drilled, cased and cemented. On March 6, 2014, the Summit Midstream cryogenic gas processing plant with a capacity of 20,000 Mcf per day started serving the company’s gas production in the southern Piceance Basin, including two Mancos Shale wells placed on production during the first quarter.

Corporate Activities

•

The company recently announced that Anthony Cleberg, executive vice president and chief financial officer, will retire at the end of March 2015. Richard Kinzley, previously vice president and controller and a 15-year veteran of the company, was appointed senior vice president and chief financial officer, effective January 1, 2015. In addition, the senior leadership team was expanded when Brian Iverson, previously vice president and treasurer and 11-year veteran of the company, was appointed senior vice president regulatory and government affairs and assistant general counsel.


•	Consolidated interest expense decreased by approximately $41 million in 2014, compared to 2013, due primarily to the refinancing activities occurring during the fourth quarter of 2013 and the extension of our Revolving Credit Facility under favorable terms on May 29, 2014.


•	On June 13, 2014, Fitch upgraded the BHC credit rating to BBB+ with a stable outlook.

•

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options for which the borrowing rates were reduced under the amended agreement.


•	On January 30, 2014, Moody’s upgraded the BHC credit rating to Baa1 from Baa2 with a stable outlook.

2013 Compared to 2012

Income from continuing operations was $118 million, or $2.66 per share, in 2013 compared to $109 million, or $2.48 per share, in 2012. The 2013 Income from continuing operations includes a $20 million non-cash after-tax mark-to-market gain on certain interest rate swaps, $6.6 million after-tax interest expense related to the early settlement of interest rate swaps and write-off of deferred financing costs associated with the prepayment of Black Hills Wyoming’s project financing and $7.6 million after-tax expense for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt. The 2012 Income from continuing operations includes a $49 million after-tax gain on sale related to the Williston Basin asset sale, a $32 million non-cash after-tax ceiling test impairment, a $1.0 million non-cash after-tax write-off of deferred financing costs related to our previous Revolving Credit Facility, a $4.6 million after-tax make-whole premium for the early redemption of our $225 million corporate notes and a $1.2 million non-cash after-tax mark-to-market gain on certain interest rate swaps.

Net income was $117 million, or $2.64 per share, in 2013 compared to $102 million, or $2.32 per share, in 2012 and includes the same items described above and losses from our Energy Marketing segment sold in February 2012.

Business Group highlights for 2013 included:

Utilities Group

Highlights of the Utilities Group include the following:


•	On September 17, 2013, the South Dakota Public Utilities Commission approved a general rate case settlement agreement authorizing an increase for Black Hills Power of $8.8 million, or 6.4%, in annual electric revenues effective June 16, 2013. The settlement agreement was confidential and certain terms were not disclosed.

•

On September 17, 2013, the SDPUC approved the construction financing rider in lieu of traditional AFUDC with an effective date of April 1, 2013. The rider allowed Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40% share of the total Cheyenne Prairie project cost that relates to South Dakota customers, while also saving customers money over the long-term. Cheyenne Light and Black Hills Power received approval from the WPSC for a similar construction financing rider in 2012 which allowed Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60% share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers.

•

Utility results for 2013 were favorably impacted by cold weather while 2012 utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported colder winter weather, as measured by heating degree days, compared to the 30-year average and the prior year. Heating degree days for the full year in 2013 were 9% higher than weighted average norms for our Gas Utilities and 25% higher than the same period in 2012.


•	During 2013, Cheyenne Light and Black Hills Power commenced construction on Cheyenne Prairie. Project costs for plant construction and associated transmission were estimated at $222 million, of which approximately $156 million was spent as of December 31, 2013.


•	In April 2013, Colorado Electric filed an Energy Resource Plan with the CPUC addressing its projected resource requirements through 2019. The resource plan identified a 40 MW, simple-cycle, natural gas-fired turbine as the replacement of W.N. Clark. On January 6, 2014, the CPUC issued its initial written decision approving construction of the turbine.


•	On April 15, 2013, the IUB approved a Capital Infrastructure Automatic Adjustment Mechanism effective April 25, 2013, for $0.2 million. This adjustment mechanism requires an annual filing, therefore, subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings.


•	On November 25, 2013, the NPSC approved an Infrastructure System Replacement Cost Recovery Charge that provided for an annual revenue increase of $1.4 million.


•	On December 31, 2013, Colorado Electric retired W.N. Clark and Pueblo Units #5 and #6. These facilities, and certain Black Hills Power generating facilities, are being permanently retired primarily due to state and federal environmental regulations. The affected plants are listed in the table below with their operations suspension date and their ultimate retirement date:



Plant	Company	MW		Type of Plant	Date Suspended	Actual Retirement Date	Age of Plant (in years)
Osage	Black Hills Power		34.5	Coal	October 1, 2010	March 21, 2014	64
Ben French	Black Hills Power		25.0	Coal	August 31, 2012	March 21, 2014	52
Neil Simpson I	Black Hills Power		21.8	Coal	NA	March 21, 2014	43
W.N. Clark	Colorado Electric		42.0	Coal	December 31, 2012	December 31, 2013	57
Pueblo Unit #5	Colorado Electric		9.0	Gas	December 31, 2012	December 31, 2013	71
Pueblo Unit #6	Colorado Electric		20.0	Gas	December 31, 2012	December 31, 2013	63
	Total MW		152.3


•	Gas Utilities continued efforts to acquire small gas distribution systems adjacent to their existing gas utility service territories. During 2013, five small gas systems with a total of approximately 900 customers were acquired.

Non-regulated Energy Group

Highlights of the Non-regulated Energy Group include the following:


•	In 2013, our Oil and Gas segment drilled and completed two horizontal wells in the Mancos Shale formation in the Piceance Basin. These wells are part of a transaction in which we earned approximately 20,000 net acres of Mancos Shale leasehold in the Piceance Basin in exchange for drilling and completing the two wells.

•

Black Hills Wyoming entered into an agreement to sell its 40 MW CTII natural-gas fired generating unit to the City of Gillette for approximately $22 million upon expiration on August 31, 2014 of the PPA with Cheyenne Light. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through ancillary agreements, including a 20-year operating agreement and a 20 year economy energy PPA. The sale closed in September 2014.

•

On September 27, 2012, our Oil and Gas segment sold approximately 85% of its Williston Basin assets, including approximately 73 gross wells and 28,000 net leasehold acres, for net cash proceeds of approximately $228 million. We recognized a gain of $76 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and had the effect of reducing the depreciation, depletion and amortization rate after the sale.


•	Coal Mining continued operations under its revised mine plan. Mining operations moved in August 2012, to an area with lower overburden ratios, which reduced mining costs in 2013.


•	In the second quarter of 2012, our Oil and Gas segment recorded a $50 million non-cash ceiling test impairment loss as a result of continued low natural gas prices.

Corporate

Activities at Corporate include the following:

•

On November 19, 2013, we completed a public debt offering of $525 million in senior unsecured debt at 4.25% due November 30, 2023. Proceeds were used to redeem our $250 million, 9% senior unsecured notes, pay off the Black Hills Wyoming project financing and related interest rate swaps, settle the de-designated interest rate swaps, partially pay down our Revolving Credit Facility and the remainder was used for other corporate purposes.

•

On September 25, 2013, Moody’s raised our corporate credit rating to Baa2 from Baa3 with continued positive outlook. On July 24, 2013, S&P raised our corporate credit rating to BBB from BBB- with a stable outlook. They also raised our senior unsecured rating to BBB from BBB-. On May 10, 2013, Fitch Ratings raised our Issuer Default Rating to BBB from BBB- with a positive outlook. Subsequently on January 30, 2014, Moody’s upgraded our corporate credit rating to Baa1 and changed their outlook to stable.


•	On June 21, 2013, we replaced our $150 million and $100 million term loans with a two-year term loan for $275 million at an interest rate of 1.125% over LIBOR.


•	We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $30 million in 2013 compared to a $1.9 million unrealized mark-to-market loss on these swaps in 2012. These swaps were settled in November 2013.

Operating Results

A discussion of operating results from our business segments follows.

All amounts are presented on a pre-tax basis unless otherwise indicated.

Utilities Group

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

In our Management Discussion and Analysis of Results of Operations, gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Gross margin for our Gas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Electric Utilities

Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):



	2014			Variance			2013			Variance			2012
Revenue - electric	$	657,556		$	29,511		$	628,045		$	32,503		$	595,542
Revenue - Cheyenne Light gas	39,754			2,491			37,263			5,839			31,424
Total revenue	697,310			32,002			665,308			38,342			626,966

Fuel and purchased power - electric	291,645			16,682			274,963			17,921			257,042
Purchased gas - Cheyenne Light	22,928			3,843			19,085			2,653			16,432
Total fuel and purchased power	314,573			20,525			294,048			20,574			273,474

Gross margin - electric	365,911			12,829			353,082			14,582			338,500
Gross margin - Cheyenne Light gas	16,826			(1,352		)	18,178			3,186			14,992
Total gross margin	382,737			11,477			371,260			17,768			353,492

Operations and maintenance	165,640			5,679			159,961			13,434			146,527
Depreciation and amortization	79,424			1,720			77,704			2,460			75,244
Total operating expenses	245,064			7,399			237,665			15,894			221,771

Operating income	137,673			4,078			133,595			1,874			131,721

Interest expense, net	(48,787		)	7,473			(56,260		)	(5,219		)	(51,041		)
Other income, net	1,164			531			633			(549		)	1,182
Income tax expense	(30,498		)	(4,664		)	(25,834		)	4,430			(30,264		)

Income from continuing operations	$	59,552		$	7,418		$	52,134		$	536		$	51,598



	2014	2013	2012
Regulated power plant fleet availability:
Coal-fired plants^(a)	93.8%	96.7%	90.8%
Other plants^(b)	90.2%	96.5%	96.9%
Total availability	91.5%	96.6%	93.9%

____________________


(a)	2014 reflects a planned overhaul on Neil Simpson II for emissions controls upgrades.


(b)	2014 reflects planned overhauls for control system upgrades to meet NERC cyber security regulations on the Ben French CT's 1-4.

2014 Compared to 2013

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $9.0 million, and increased rider margins from Cheyenne Prairie by $5.5 million. Industrial megawatt hours sold increased by approximately 15%, primarily due to load growth at Cheyenne Light resulting in increased margins of $1.7 million. Facility improvements at one of our large industrial customers drove a $1.8 million increase in technical service revenues. These increases were partially offset by a $3.5 million decrease from lower demand and residential megawatt hours sold driven by a 29% decrease in cooling degree days compared to the same period in the prior year, a $1.6 million decrease from the TCA, and a $0.8 million decrease from a construction savings incentive recognized in the prior year. Our Cheyenne Light gas utility experienced a decrease in heating degree days, resulting in a $1.4 million decrease in retail natural gas sales.

Operations and maintenance increased primarily due to property taxes, regulatory support and legal fees, generation maintenance, and employee costs.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie.

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013, and extending our revolving credit facility under favorable terms during the second quarter of 2014.

Income tax benefit (expense): The effective tax rate was comparable to the same period in the prior year.

2013 Compared to 2012

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $5.9 million, increased rider margins by $9.4 million and a $2.2 million increase at our gas utility due to an increase in volumes driven by a 17% increase in heating degree days. These are partially offset by a $2.1 million construction savings incentive received by Colorado Electric in 2012 compared to $0.7 million received in 2013.

Operations and maintenance increased primarily due to property taxes, vegetation management and employee costs. Prior year included a $2.1 million reduction of major maintenance accruals related to plant suspensions and retirements.

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net increased primarily due to lower AFUDC.

Income tax benefit (expense): The effective tax rate decreased primarily due to an unfavorable income tax true-up adjustment that impacted 2012.

Gas Utilities

Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):



	2014			Variance			2013			Variance			2012
Revenue:
Natural gas - regulated	$	587,378		$	77,123		$	510,255		$	84,987		$	425,268
Other - non-regulated	30,390			956			29,434			621			28,813
Total revenue	617,768			78,079			539,689			85,608			454,081

Cost of natural gas sold:
Natural gas - regulated	365,034			69,609			295,425			64,163			231,262
Other - non-regulated	15,818			780			15,038			951			14,087
Total cost of natural gas sold	380,852			70,389			310,463			65,114			245,349

Gross margin:
Natural gas - regulated	222,344			7,514			214,830			20,824			194,006
Other - non-regulated	14,572			176			14,396			(330		)	14,726
Total gross margin	236,916			7,690			229,226			20,494			208,732

Operations and maintenance	132,635			6,562			126,073			8,683			117,390
Depreciation and amortization	26,499			118			26,381			1,218			25,163
Total operating expenses	159,134			6,680			152,454			9,901			142,553

Operating income	77,782			1,010			76,772			10,593			66,179

Interest expense, net	(15,284		)	8,974			(24,258		)	(277		)	(23,981		)
Other expense (income), net	34			94			(60		)	(165		)	105
Income tax expense	(20,663		)	(916		)	(19,747		)	(5,434		)	(14,313		)

Income from continuing operations	$	41,869		$	9,162		$	32,707		$	4,717		$	27,990

2014 Compared to 2013

Gross margin increased primarily due to higher transport volumes which increased transport margins by $1.7 million. Rider margins increased $2.9 million primarily due to additional capital investments, and $1.6 million of additional margin was attributed to year over year customer growth. Higher retail volumes sold, driven mostly by a 7 percent increase in heating degree days realized in the first quarter of 2014 resulted in a $1.2 million increase. Heating degree days for the twelve months ended December 31, 2014, were 2% lower than the same period in the prior year, and 7% higher than normal.

Operations and maintenance increased primarily due to employee costs, property taxes, outside services, and uncollectible accounts attributed to increased revenue.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.

Income tax: The effective tax rate for 2014 was lower primarily due to a favorable true-up adjustment to the filed 2013 income tax return, in addition to an increase in flow-through tax adjustments.

2013 Compared to 2012

Gross margin increased primarily due to a $12 million increase resulting from higher retail volumes driven by a 25% increase in heating degree days. Transport margins increased $2.9 million, surcharge revenue increased $1.9 million primarily due to additional capital investments and $1.3 million of additional margin was attributed to year over year customer growth.

Operations and maintenance increased primarily due to employee costs, property taxes and uncollectible accounts attributed to increased revenue.

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net was comparable to the same period in the prior year.

Income tax: The effective tax rate for 2013 increased primarily as a result of favorable flow-through tax adjustment that benefited 2012.

Non-regulated Energy Group

Power Generation

Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):



	2014			Variance			2013			Variance			2012

Revenue	$	87,558		$	4,521		$	83,037		$	3,648		$	79,389

Operations and maintenance	33,126			2,940			30,186			195			29,991
Depreciation and amortization	4,540			(551		)	5,091			492			4,599
Total operating expenses	37,666			2,389			35,277			687			34,590

Operating income	49,892			2,132			47,760			2,961			44,799

Interest expense, net	(3,669		)	16,724			(20,393		)	(5,636		)	(14,757		)
Other income (expense), net	(6		)	(7		)	1			(6		)	7
Income tax expense	(17,701		)	(6,621		)	(11,080		)	(2,359		)	(8,721		)

Income from continuing operations	$	28,516		$	12,228		$	16,288		$	(5,040	)	$	21,328



	2014	2013	2012
Contracted fleet plant availability:
Gas-fired plants	99.0%	99.0%	99.4%
Coal-fired plants ^(a)	94.7%	94.5%	99.6%
Total	97.8%	97.9%	99.4%

__________________________


(a)	Wygen I experienced planned outages in 2014 and 2013.

2014 Compared to 2013

Revenue increased primarily due to an increase in megawatt hours delivered at higher prices, an increase in fired hours, and an increase from the new economy energy PPA with the City of Gillette, partially offset by the expiration of the CTII capacity contract with Cheyenne Light.

Operations and maintenance increased primarily due to increased outside services and materials, and additional maintenance costs on the Wygen I outage, partially offset by decreased employee costs.

Depreciation and amortization decreased primarily due to lower depreciation at Black Hills Wyoming. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased primarily due to refinancing higher cost project debt and settling associated interest rate swaps in the fourth quarter of 2013. The fourth quarter of 2013 included $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs.

Income tax expense: The effective tax rate was comparable to the same period in the prior year.

2013 Compared to 2012

Revenue increased primarily due to $2.1 million relating to increased MWh delivered at higher prices and $2.3 million related to increased volumes and pricing for off-system sales at Black Hills Wyoming.

Operations and maintenance increased primarily due to two Wygen I outages, partially offset by decreased property taxes at Black Hills Colorado IPP.

Depreciation and amortization were comparable to the same period in the prior year. The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased primarily due to $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs, partially offset by lower inter-company debt.

Income tax expense: The effective tax rate in 2013 increased as a result of an unfavorable tax true-up adjustment.

Coal Mining

Coal Mining operating results for the years ended December 31 were as follows (in thousands):



	2014			Variance			2013			Variance			2012

Revenue	$	63,358		$	6,730		$	56,628		$	(1,150	)	$	57,778

Operations and maintenance	41,172			1,653			39,519			(3,034		)	42,553
Depreciation, depletion and amortization	10,276			(1,247		)	11,523			(1,537		)	13,060
Total operating expenses	51,448			406			51,042			(4,571		)	55,613

Operating income (loss)	11,910			6,324			5,586			3,421			2,165

Interest (expense) income, net	(434		)	197			(631		)	(1,561		)	930
Other income, net	2,275			(29		)	2,304			(312		)	2,616
Income tax benefit (expense)	(3,299		)	(2,367		)	(932		)	(847		)	(85		)
Income (loss) from continuing operations	$	10,452		$	4,125		$	6,327		$	701		$	5,626

The following table provides certain operating statistics for the Coal Mining segment (in thousands):



	2014	2013		2012
Tons of coal sold	4,317	4,285		4,246

Cubic yards of overburden moved	4,646	3,192	^(a)	8,329

Coal reserves at year-end	208,231	212,595	^(b)	232,265

____________


(a)	Reduction in overburden was due to relocating mining operations in the second half of 2012 to an area of the mine with lower overburden.


(b)	Reduction in coal reserves was due to revisions in coal modeling based upon engineering data, changes in coal limit boundaries and current coal production.

2014 Compared to 2013

Revenue increased primarily due to an 11% increase in the price per ton sold driven primarily by a coal price increase with the third-party operator of the Wyodak plant. Price per ton also increased as a result of an increase in pricing on contracts containing price adjustments based on actual mining costs. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have increased due to higher operations and maintenance costs driven by mining in areas with a higher stripping ratio than the prior year, thereby increasing our price per ton for these customers.

Operations and maintenance increased primarily due to mining in areas with higher overburden, materials and outside services on major maintenance projects, and an increase in royalties and revenue related taxes driven by increased revenue, partially offset by lower employee costs.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets driven by a reduction in equipment run hours from changes in the mine plan design, and lower depreciation of mine reclamation costs.

Interest (expense) income, net is comparable to the same period in the prior year.

Income tax: The effective tax rate in 2014 is higher due to the reduced impact of the tax benefit of percentage depletion.

2013 Compared to 2012

Revenue decreased primarily due to a 9% decrease in the average price per ton charged on coal sold under contracts containing price adjustments, partially offset by a 1% increase in tons sold. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have trended down due to lower operations and maintenance costs, thereby decreasing our price per ton for these customers.

Operations and maintenance decreased primarily due to mining in areas with lower overburden, resulting in decreased fuel costs and reduced employee costs, partially offset by materials and outside services related to major maintenance projects.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets and lower depreciation of mine reclamation costs.

Interest (expense) income, net reflects decreased interest income primarily due to a decrease in the inter-company notes receivable, reduced by payment of a dividend to our parent.

Income tax benefit (expense): The effective tax rate increased in 2013 as a result of lower percentage depletion. In addition, the effective tax rate in 2012 was impacted by a favorable true-up adjustment that was primarily driven by an increased percentage depletion deduction reported on the 2011 tax return.

Oil and Gas

Oil and Gas operating results for the years ended December 31 were as follows (in thousands):



	2014			Variance			2013			Variance			2012

Revenue	$	55,114		$	230		$	54,884		$	(24,188	)	$	79,072

Operations and maintenance	42,659			2,294			40,365			(2,902		)	43,267
Gain on sale of assets	—			—			—			75,854			(75,854		)
Depreciation, depletion and amortization	24,246			6,369			17,877			(11,908		)	29,785
Impairment of long-lived assets	—			—			—			(49,571		)	49,571
Total operating expenses	66,905			8,663			58,242			11,473			46,769

Operating income (loss)	(11,791		)	(8,433		)	(3,358		)	(35,661		)	32,303

Interest expense, net	(1,685		)	(1,071		)	(614		)	3,321			(3,935		)
Other income (expense), net	183			75			108			(99		)	207
Income tax benefit (expense)	4,768			2,655			2,113			12,005			(9,892		)

Income (loss) from continuing operations	$	(8,525	)	$	(6,774	)	$	(1,751	)	$	(20,434	)	$	18,683

The following tables provide certain operating statistics for the Oil and Gas segment:



Crude Oil and Natural Gas Production	2014	2013	2012
Bbls of oil sold	337,196	336,140	559,971
Mcf of natural gas sold	7,155,076	6,983,104	8,686,191
Bbls of NGL sold	134,555	88,205	82,989
Mcf equivalent sales	9,985,584	9,529,178	12,543,948



Average Price Received ^(a)	2014		2013		2012
Gas/Mcf	$	2.91	$	2.69	$	3.33
Oil/Bbl	$	79.39	$	89.34	$	83.27
NGL/Bbl	$	35.53	$	33.15	$	32.41

__________________________


(a)	Net of hedge settlement gains/losses



	2014		2013		2012
Depletion expense/Mcfe*	$	1.84	$	1.40	$	2.11

___________


*	The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The decreased depletion rate in 2013 is primarily driven by the Williston Basin sale and ceiling test impairment in 2012. See Note 21 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K/A.

The following is a summary of certain annual average costs per Mcfe at December 31:



	2014
	LOE		Gathering, Compression, Processingand Transportation		Production Taxes		Total
San Juan	$	1.52	$	1.11	$	0.56	$	3.19
Piceance	0.31		3.74		0.38		4.43
Powder River	1.77		—		1.26		3.03
Williston	1.46		—		1.24		2.70
All other properties	1.43		—		0.43		1.86
Average	$	1.24	$	1.37	$	0.68	$	3.29



	2013
	LOE		Gathering, Compression, Processingand Transportation		Production Taxes		Total
San Juan	$	1.33	$	0.96	$	0.45	$	2.74
Piceance	0.69		1.68		0.04		2.41
Powder River	1.66		—		1.18		2.84
Williston	1.06		—		1.38		2.44
All other properties	0.86		—		0.18		1.04
Average	$	1.22	$	0.66	$	0.60	$	2.48



	2012
	LOE		Gathering, Compression, Processingand Transportation		Production Taxes		Total
San Juan	$	1.22	$	0.71	$	0.35	$	2.28
Piceance	0.30		1.29		0.17		1.76
Powder River	1.57		—		1.18		2.75
Williston	0.35		—		1.35		1.70
All other properties	1.91		—		0.34		2.25
Average	$	1.05	$	0.49	$	0.64	$	2.18

In the Piceance and San Juan Basins, our natural gas is transported through our own and third-party gathering systems and pipelines, for which we incur processing, gathering, compression and transportation fees. The sales price for natural gas, condensate and NGLs is reduced for these third-party costs, and the cost of operating our own gathering systems is included in operations and maintenance. The gathering, compression, processing and transportation costs shown in the tables above include amounts paid to third parties, as well as costs incurred in operations associated with our own gas gathering, compression, processing and transportation.

We revised our presentation of these costs in 2014 to include both third-party costs and operations costs, and have restated the 2013 and 2012 amounts accordingly. Our 2014 amounts were impacted by a ten-year gas gathering and processing contract for natural gas production in our Piceance Basin in Colorado that became effective in 2014. This take or pay contract requires us to pay the fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. In 2014 our delivery of production did not meet the minimum requirement; therefore our cost per Mcfe increased as illustrated in the table above.

The following is a summary of our proved oil and gas reserves at December 31:



	2014	2013	2012
Bbls of oil (in thousands)	4,276	3,921	4,116
MMcf of natural gas	65,440	63,190	55,985
Bbls of NGLs (in thousands) ^(a)	1,720	—	—
Total MMcfe	101,416	86,713	80,683

__________

(a) NGL reserves for 2013 and 2012 are not available and were included with MMcf of natural gas in 2013 and 2012.

Reserves are based on reports prepared by an independent consulting and engineering firm. The reports were prepared by CG&A. Reserves were determined using SEC-defined product prices. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The current estimate takes into account 2014 production of approximately 10.0 Bcfe, additions from extensions, discoveries and acquisitions (sales) of 16.2 Bcfe and positive revisions to previous estimates of 8.5 Bcfe, primarily due to oil and natural gas pricing.

Reserves reflect SEC-defined pricing held constant for the life of the reserves, as follows:



	2014				2013				2012
	Oil		Gas		Oil		Gas		Oil		Gas
NYMEX prices	$	94.99	$	4.35	$	96.94	$	3.67	$	94.71	$	2.76
Well-head reserve prices	$