Edgar Filing: BLACK HILLS CORP /SD/

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2016
OR
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	IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

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 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 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

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



Class	Outstanding at April 30, 2016
Common stock, $1.00 par value	51,587,415	shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	6

Item 1.	Financial Statements	6

	Condensed Consolidated Statements of Income (Loss) - unaudited
	Three Months Ended March 31, 2016 and 2015	6

	Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
	Three Months Ended March 31, 2016 and 2015	7

	Condensed Consolidated Balance Sheets - unaudited
	March 31, 2016, December 31, 2015 and March 31, 2015	8

	Condensed Consolidated Statements of Cash Flows - unaudited
	Three Months Ended March 31, 2016 and 2015	10

	Notes to Condensed Consolidated Financial Statements - unaudited	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	74

Item 4.	Controls and Procedures	75

PART II.	OTHER INFORMATION	76

Item 1.	Legal Proceedings	76

Item 1A.	Risk Factors	76

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	77

Item 4.	Mine Safety Disclosures	77

Item 5.	Other Information	77

Item 6.	Exhibits	78

	Signatures	80

	Index to Exhibits	81

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
APSC	Arkansas Public Service Commission
ASU	Accounting Standards Update issued by the FASB
ATM	At-the-market equity offering program
Bbl	Barrel
BHC	Black Hills Corporation; the Company
Black Hills Gas	Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC.
Black Hills Gas Holdings	Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility companies
Black Hills Energy Arkansas Gas	Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations
Black Hills Energy Colorado Electric	Includes all of Colorado Electric’s utility operations
Black Hills Energy Colorado Gas	Includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG
Black Hills Energy Iowa Gas	Includes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas Gas	Includes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska Gas	Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy South Dakota Electric	Includes all Black Hills Power operations in South Dakota, Wyoming and Montana
Black Hills Energy Wyoming Electric	Includes all of Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming Gas	Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas Distribution	Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu	British thermal unit
Ceiling Test	Related to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power, Inc. and Cheyenne Light, Fuel and Power Company. Cheyenne Prairie was placed into commercial service on October 1, 2014.
CIAC	Contribution In Aid of Construction



City of Gillette	Gillette, Wyoming
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP	Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
Cooling degree day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
Cost of Service Gas Program	A program our utility subsidiaries submitted applications for with respective state utility regulators in Iowa, Kansas, Nebraska, South Dakota, Colorado and Wyoming, seeking approval for a Cost of Service Gas Program designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CTII	The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.
CVA	Credit Valuation Adjustment
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Energy West	Energy West Wyoming, Inc., a subsidiary of Gas Natural, Inc. Energy West is an acquisition we closed on July 1, 2015 (doing business as Black Hills Energy)
EPA	United States Environmental Protection Agency
Equity Unit	Each Equity Unit has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RNSs due 2028.
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent power producer
IRS	United States Internal Revenue Service
IUB	Iowa Utilities Board
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
KCC	Kansas Corporation Commission
kV	Kilovolt
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	Thousand cubic feet
Mcfe	Thousand cubic feet equivalent.
MGTC	MGTC, Inc., a gas utility in northeast Wyoming serving 400 customers. MGTC is an acquisition we closed on January 1, 2015 (doing business as Black Hills Energy)



MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
MWh	Megawatt-hours
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NGL	Natural Gas Liquids (1 barrel equals 6 Mcfe)
NOL	Net Operating Loss
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
Peak View Wind Project	New $109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm
PPA	Power Purchase Agreement
Recourse Leverage Ratio	Any indebtedness outstanding at such time, divided by Capital at such time. Capital being consolidated net-worth plus all recourse indebtedness.
Revolving Credit Facility	Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2020.
RMNG	Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy)
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
SourceGas	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
S&P	Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)



(unaudited)	Three Months Ended March 31,
	2016			2015
	(in thousands, except per share amounts)

Revenue	$	449,959		$	441,987

Operating expenses:
Fuel, purchased power and cost of natural gas sold	171,856			205,327
Operations and maintenance	107,062			93,134
Depreciation, depletion and amortization	44,407			39,002
Taxes - property, production and severance	12,117			11,936
Impairment of long-lived assets	14,496			22,036
Other operating expenses	26,431			52
Total operating expenses	376,369			371,487

Operating income (loss)	73,590			70,500

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(32,074		)	(19,910		)
Allowance for funds used during construction - borrowed	501			158
Capitalized interest	235			276
Interest income	655			448
Allowance for funds used during construction - equity	707			56
Other income (expense), net	688			331
Total other income (expense), net	(29,288		)	(18,641		)

Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	44,302			51,859
Equity in earnings (loss) of unconsolidated subsidiaries	—			(297		)
Income tax benefit (expense)	(4,252		)	(17,712		)
Net income (loss)	40,050			33,850
Net income attributable to non-controlling interest	(48		)	—
Net income (loss) available for common stock	$	40,002		$	33,850

Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic	$	0.78		$	0.76
Earnings (loss) per share, Diluted	$	0.77		$	0.76
Weighted average common shares outstanding:
Basic	51,044			44,541
Diluted	51,858			44,660

Dividends declared per share of common stock	$	0.420		$	0.405

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



(unaudited)	Three Months Ended March 31,
	2016			2015
	(in thousands)

Net income (loss)	$	40,050		$	33,850

Other comprehensive income (loss), net of tax:
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $4,576 and $(1,042) for the three months ended 2016 and 2015, respectively)	(8,644		)	1,836
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $1,946 and $1,254 for the three months ended 2016 and 2015, respectively)	(3,412		)	(1,241		)
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $0 and $15 for the three months ended 2016 and 2015, respectively)	—			(27		)
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $19 for the three months ended 2016 and 2015, respectively)	(36		)	(36		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(172) and $(247) for the three months ended 2016 and 2015, respectively)	322			458
Other comprehensive income (loss), net of tax	(11,770		)	990

Comprehensive income (loss)	28,280			34,840
Less: comprehensive income attributable to non-controlling interest	(48		)	—
Comprehensive income (loss) available for common stock	$	28,232		$	34,840

See Note 15 for additional disclosures.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



(unaudited)	As of
	March 31, 2016			December 31, 2015			March 31, 2015
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	46,974		$	456,535		$	63,385
Restricted cash and equivalents	1,839			1,697			2,191
Accounts receivable, net	206,276			147,486			178,421
Materials, supplies and fuel	78,176			86,943			66,626
Derivative assets, current	1,486			—			—
Income tax receivable, net	—			368			159
Deferred income tax assets, net, current	—			—			23,913
Regulatory assets, current	54,108			57,359			56,542
Other current assets	34,287			71,763			47,448
Total current assets	423,146			822,151			438,685

Investments	12,126			11,985			17,210

Property, plant and equipment	6,063,943			4,976,778			4,652,058
Less: accumulated depreciation and depletion	(1,742,070		)	(1,717,684		)	(1,407,214		)
Total property, plant and equipment, net	4,321,873			3,259,094			3,244,844

Other assets:
Goodwill	1,306,169			359,759			353,396
Intangible assets, net	10,957			3,380			3,121
Regulatory assets, non-current	239,023			175,125			178,935
Derivative assets, non-current	85			3,441			—
Other assets, non-current	11,274			7,382			16,994
Total other assets, non-current	1,567,508			549,087			552,446

TOTAL ASSETS	$	6,324,653		$	4,642,317		$	4,253,185

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)



(unaudited)	As of
	March 31, 2016			December 31, 2015			March 31, 2015
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	121,684		$	105,468		$	88,770
Accrued liabilities	272,181			232,061			166,781
Derivative liabilities, current	3,965			2,835			3,342
Accrued income taxes, net	10,899			—			—
Regulatory liabilities, current	35,933			4,865			17,621
Notes payable	215,600			76,800			102,600
Total current liabilities	660,262			422,029			379,114

Long-term debt	3,159,055			1,853,682			1,531,372

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	500,202			450,579			503,117
Derivative liabilities, non-current	14,522			156			2,143
Regulatory liabilities, non-current	200,337			148,176			148,918
Benefit plan liabilities	181,270			146,459			162,334
Other deferred credits and other liabilities	124,181			155,369			154,604
Total deferred credits and other liabilities	1,020,512			900,739			971,116

Commitments and contingencies (See Notes 9, 10, 17, 18)

Redeemable non-controlling interest	4,141			—			—

Stockholders’ equity:
Common stock equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 51,477,472; 51,231,861; and 44,856,790 shares, respectively	51,477			51,232			44,857
Additional paid-in capital	960,605			953,044			749,517
Retained earnings	490,999			472,534			592,951
Treasury stock, at cost – 30,903; 39,720; and 33,755 shares, respectively	(1,573		)	(1,888		)	(1,688		)
Accumulated other comprehensive income (loss)	(20,825		)	(9,055		)	(14,054		)
Total stockholders’ equity	1,480,683			1,465,867			1,371,583

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	6,324,653		$	4,642,317		$	4,253,185

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



(unaudited)	Three Months Ended March 31,
	2016			2015
Operating activities:	(in thousands)
Net income (loss) available for common stock	$	40,002		$	33,850
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	44,407			39,002
Deferred financing cost amortization	1,666			519
Impairment of long-lived assets	14,496			22,036
Stock compensation	4,461			2,083
Deferred income taxes	32,579			14,640
Employee benefit plans	3,466			5,283
Other adjustments, net	(5,000		)	6,748
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	25,822			25,689
Accounts receivable, unbilled revenues and other operating assets	27,559			13,954
Accounts payable and other operating liabilities	(68,101		)	(44,652		)
Regulatory assets - current	12,856			20,272
Regulatory liabilities - current	11,613			13,721
Other operating activities, net	(7,489		)	(1,658		)
Net cash provided by (used in) operating activities	138,337			151,487

Investing activities:
Property, plant and equipment additions	(83,885		)	(117,523		)
Acquisition, net of long term debt assumed and cash acquired	(1,132,318		)	—
Other investing activities	(329		)	(348		)
Net cash provided by (used in) investing activities	(1,216,532		)	(117,871		)

Financing activities:
Dividends paid on common stock	(21,537		)	(18,148		)
Common stock issued	7,821			999
Short-term borrowings - issuances	208,100			77,700
Short-term borrowings - repayments	(69,300		)	(50,100		)
Long-term debt - issuances	545,959			—
Other financing activities	(2,409		)	(1,900		)
Net cash provided by (used in) financing activities	668,634			8,551
Net change in cash and cash equivalents	(409,561		)	42,167
Cash and cash equivalents, beginning of period	456,535			21,218
Cash and cash equivalents, end of period	$	46,974		$	63,385

See Note 16 for supplemental disclosure of cash flow information.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2015 Annual Report on Form 10-K)

(1) MANAGEMENT’S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2015 Annual Report on Form 10-K filed with the SEC.

Segment Reporting

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our utilities, other than the Oil and Gas segment, and in 2015 we began transitioning the Oil and Gas business to support utilities through a Cost of Service Gas Program. The following changes have been made to our Condensed Consolidated Statements of Income to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three months ended March 31, 2015:



	For the Three Months Ended March 31, 2015
(in thousands)	As Previously Reported		Presentation Reclassification			As Currently Reported
Utilities - operations and maintenance	$	71,084	$	(71,084	)	$	—
Non-regulated energy operations and maintenance	$	22,050	$	(22,050	)	$	—
Operations and maintenance	$	—	$	93,134		$	93,134

This presentation reclassification did not impact our financial position, results of operations or cash flows.

Segment reporting transition of Cheyenne Light’s natural gas distribution

Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior period has been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 3 for Revenues, Net Income and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the period ending March 31, 2015. This segment reclassification did not impact our consolidated financial position, results of operations or cash flows.

Use of estimates and basis of presentation

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2016, December 31, 2015, and March 31, 2015 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2016 and March 31, 2015, and our financial condition as of March 31, 2016, December 31, 2015, and March 31, 2015, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Significant Accounting Policies

Business Combinations

We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. Our significant assumptions and estimates can include, but are not limited to, the cash flows that an acquired entity is expected to generate in the future, the appropriate weighted-average cost of capital, and the savings expected to be derived from the business combination. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for our acquisition.

Recently Issued and Adopted Accounting Standards

Improvements to Employee Share-Based Payment Accounting, ASU 2016-09

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently assessing the impact that adoption of ASU 2016-09 will have on its consolidated financial position, results of operations, cash flows, and disclosure.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2019. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. We are currently assessing the impact that adoption of ASU 2014-09 will have on our financial position, results of operations or cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07

On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent). The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of March 31, 2016, we have presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million and $11 million in the Condensed Consolidated Balance Sheets as of December 31 2015 and March 31, 2015, respectively. Adoption of ASU 2015-03 did not have a material impact on our financial position.

Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16

In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of March 31, 2016. Adoption of this standard did not have a material impact on the Company’s financial position, results of operations or cash flows.

(2) ACQUISITION

Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. The purchase price is subject to post-closing adjustments for capital expenditures, indebtedness and working capital, which will be determined and agreed to, subject to a review period. SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado.

Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock and 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility.

In connection with the acquisition, we recorded pre-tax acquisition costs of approximately $25 million in the three months ended March 31, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Condensed Consolidating Income Statements. No acquisition costs were recorded in the three months ended March 31, 2015.

Our consolidated operating results for the three months ended March 31, 2016 include revenues of $76 million and net income of $7.6 million attributable to SourceGas for the period from February 12 through March 31, 2016. SourceGas is included in our Gas Utilities reporting segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers.

We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.

We are still determining the purchase price allocation for SourceGas. A preliminary purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.132 billion, net of long-term debt assumed of $760 million and cash acquired of $2.5 million, resulted in a preliminary estimate of goodwill totaling $946 million. These estimates are subject to change and will likely result in an increase or decrease in goodwill, which could be material. We have up to one year from the acquisition date to finalize the purchase price allocation. Approximately $219 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities.



	(in thousands)

Preliminary Purchase Price	$	1,894,882
Less: Long-term debt assumed	(760,000		)
Consideration Paid	$	1,134,882

Preliminary Allocation of Purchase Price:
Current Assets	$	119,549
Property, plant & equipment, net	1,015,200
Goodwill	946,410
Deferred charges and other assets, excluding goodwill	136,240
Current liabilities	(172,710		)
Long-term debt	(760,000		)
Deferred credits and other liabilities	(149,807		)
Total preliminary consideration paid	$	1,134,882

Conditions of Approval

The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below:

The APSC order includes a 12 month base rate moratorium, an annual $0.25 million customer credit for a term of up to five-years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The CPUC order includes a two-year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three-year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five-years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The NPSC order includes a three-year base rate moratorium, a three-year continuation of the Choice Gas program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The WPSC order includes a three-year continuation of the Choice Gas program, as well as various other terms and reporting requirements.

All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs are disallowed in Arkansas, Colorado and Nebraska, however Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs.

Pro Forma Results

We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the three months ended March 31, 2016 and March 31, 2015. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015:



	Pro Forma Results
	For the Three Months Ended
	March 31, 2016		March 31, 2015
	(in thousands, except per share amounts)
Revenue	$	528,921	$	628,464
Net income (loss) available for common stock	$	66,690	$	52,041
Earnings (loss) per share, Basic	$	1.31	$	1.02
Earnings (loss) per share, Diluted	$	1.29	$	1.01

We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the three months ended March 31, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the Acquisition, and exclude any unique one-time items that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three months ended March 31, 2016 reflect lower gas pricing than in 2015 and tax benefits realized in the first quarter of 2016, as described in Footnote 20. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%.

These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future.

Seller’s non-controlling interest

One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas transaction. If we choose not to exercise this option during a ninety-day period, the seller is provided a put option to sell us the retained interest.

(3) BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):



Three Months Ended March 31, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss)
Segment:
Electric	$	163,531	$	3,745		$	19,215
Gas	268,667		1,806			31,975
Power Generation	1,852		21,456			8,582
Mining	7,534		8,748			2,938
Oil and Gas ^(a)	8,375		—			(7,024		)
Corporate activities^(b)(d)	—		—			(15,684		)
Inter-company eliminations	—		(35,755		)	—
Total	$	449,959	$	—		$	40,002



Three Months Ended March 31, 2015	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss)
Segment:
Electric ^(c)	$	166,493	$	3,424		$	17,553
Gas ^(c)	254,132		—			23,588
Power Generation	1,953		20,721			8,145
Mining	8,142		7,792			3,010
Oil and Gas ^(a)	11,267		—			(19,115		)
Corporate activities	—		—			669
Inter-company eliminations	—		(31,937		)	—
Total	$	441,987	$	—		$	33,850


(a)	Net income (loss) for the three months ended March 31, 2016 and March 31, 2015 include non-cash after-tax ceiling test impairments of $8.8 million and $14 million, respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


(b)	Net income (loss) for the three months ended March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $15 million and after-tax internal labor costs attributable to the acquisition of $3.8 million. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(c)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue and Net Income of $16 million and $1.4 million, respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment.


(d)	Includes net income attributable to non-controlling interest of $0.1 million.

Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):



Total Assets (net of inter-company eliminations) as of:	March 31, 2016		December 31, 2015		March 31, 2015
Segment:
Electric ^{(a) (b)}	$	2,714,450	$	2,720,004	$	2,691,822
Gas ^(b)	3,146,315		999,778		960,435
Power Generation ^(a)	74,403		60,864		75,945
Mining	73,878		76,357		77,399
Oil and Gas ^(c)	197,291		208,956		348,300
Corporate activities ^(d)	118,316		576,358		99,284
Total assets	$	6,324,653	$	4,642,317	$	4,253,185

__________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

(b)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $121 million, respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and March 31, 2015.

(c)

As a result of continued low commodity prices during 2016 and 2015, we recorded non-cash impairments of oil and gas assets included in our Oil and Gas segment of $14 million for the for the three months ended March 31, 2016, $250 million for the year ended December 31, 2015, and $22 million for the three months ended March 31, 2015. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


(d)	Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016.

(4) ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2016	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,981	$	32,660	$	(772	)	$	73,869
Gas Utilities	73,259		55,014		(4,363		)	123,910
Power Generation	1,210		—		—			1,210
Mining	2,484		—		—			2,484
Oil and Gas	2,395		—		(13		)	2,382
Corporate	2,421		—		—			2,421
Total	$	123,750	$	87,674	$	(5,148	)	$	206,276



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2015	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities ^(a)	$	41,679	$	35,874	$	(727	)	$	76,826
Gas Utilities ^(a)	30,331		32,869		(1,001		)	62,199
Power Generation	1,187		—		—			1,187
Mining	2,760		—		—			2,760
Oil and Gas	3,502		—		(13		)	3,489
Corporate	1,025		—		—			1,025
Total	$	80,484	$	68,743	$	(1,741	)	$	147,486



	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2015	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities ^(a)	$	49,046	$	23,088	$	(873	)	$	71,261
Gas Utilities ^(a)	68,068		30,237		(1,549		)	96,756
Power Generation	1,152		—		—			1,152
Mining	3,638		—		—			3,638
Oil and Gas	4,646		—		(13		)	4,633
Corporate	981		—		—			981
Total	$	127,531	$	53,325	$	(2,435	)	$	178,421

___________

(a)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $6.3 million as of December 31, 2015 and March 31, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

(5) REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):



	Maximum	As of		As of		As of
	Amortization (in years)	March 31, 2016		December 31, 2015		March 31, 2015
Regulatory assets
Deferred energy and fuel cost adjustments - current^{(a) (d)}	1	$	24,479	$	24,751	$	30,833
Deferred gas cost adjustments ^(a)(d)	1	14,895		15,521		6,138
Gas price derivatives ^(a)	7	20,324		23,583		21,606
AFUDC^(b)	45	13,677		12,870		12,114
Employee benefit plans ^{(c) (e)}	12	111,661		83,986		97,700
Environmental^(a)	subject to approval	1,162		1,180		1,240
Asset retirement obligations^(a)	44	487		457		3,237
Bond issue cost^(a)	22	3,097		3,133		3,240
Renewable energy standard adjustment ^(b)	5	4,507		5,068		5,590
Flow through accounting^(c)	35	30,614		29,722		26,835
Decommissioning costs ^(f)	10	18,134		18,310		13,702
Gas supply contract termination	5	30,613		—		—
Other regulatory assets^(a)	15	19,481		13,903		13,242
		$	293,131	$	232,484	$	235,477

Regulatory liabilities
Deferred energy and gas costs^{(a) (d)}	1	$	40,797	$	7,814	$	18,094
Employee benefit plans^{(c) (e)}	12	63,580		47,218		53,151
Cost of removal^(a)	44	123,076		90,045		81,449
Other regulatory liabilities^(c)	25	8,817		7,964		13,845
		$	236,270	$	153,041	$	166,539

__________


(a)	Recovery of costs, but we are not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d)

Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.


(e)	Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans.


(f)	South Dakota Electric has approximately $13 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs.

Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements vary, currently ranging from $6 to $8 per MMBtu, and exceed market prices. We recorded a liability for this contract in our purchase price allocation. We applied for and subsequent to March 31, 2016, we were granted approval to terminate these agreements with the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We settled the liability on April 29, 2016. See Note 22.

(6) MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2016		December 31, 2015		March 31, 2015
Materials and supplies	$	66,542	$	55,726	$	52,429
Fuel - Electric Utilities	5,365		5,567		6,780
Natural gas in storage held for distribution	6,269		25,650		7,417
Total materials, supplies and fuel	$	78,176	$	86,943	$	66,626

(7) GOODWILL & INTANGIBLE ASSETS

Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands):



	Electric Utilities ^(b)		Gas Utilities ^(b)		Power Generation		Total
Ending balance at December 31, 2015	$	250,487	$	100,507	$	8,765	$	359,759
Acquisition of SourceGas ^(a)	—		946,410		—		946,410
Ending balance at March 31, 2016	$	250,487	$	1,046,917	$	8,765	$	1,306,169

__________


(a)	Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.


(b)	Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details.

Following is a summary of Intangible assets included in the accompanying Condensed Consolidated Balance Sheets (in thousands):



Intangible assets, net beginning balance December 31, 2015	$	3,380
Additions, net ^(a)	7,734
Amortization expense	(157		)
Intangible assets, net, ending balance at March 31, 2016	$	10,957

__________


(a)	Intangible assets, net acquired from SourceGas are primarily trademarks and tradenames, and are amortized over 5-year estimated useful lives. See Note 2 for more information.

(8) EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands):



	Three Months Ended March 31,
	2016		2015

Net income (loss) available for common stock	$	40,002	$	33,850

Weighted average shares - basic	51,044		44,541
Dilutive effect of:
Equity Units ^(a)	720		—
Equity compensation	94		119
Weighted average shares - diluted	51,858		44,660

__________


(a)	Calculated using the treasury stock method.

The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):



	Three Months Ended March 31,
	2016	2015

Equity compensation	74	107
Anti-dilutive shares	74	107

(9) NOTES PAYABLE

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	March 31, 2016				December 31, 2015				March 31, 2015
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	215,600	$	24,000	$	76,800	$	33,399	$	102,600	$	22,300

Revolving Credit Facility

On June 26, 2015, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through June 26, 2020. This facility is 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. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P and/or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at March 31, 2016. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating.

Debt Financial Covenants

On February 12, 2016, in connection with the SourceGas Acquisition discussed in Note 2, our Revolving Credit Facility and Term Loan credit agreements were amended to permit the assumption of certain indebtedness of SourceGas and to increase the Recourse Leverage Ratio, and we amended and restated SourceGas’s $340 million term loan due June 30, 2017. On February 12, 2016, the maximum Recourse Leverage Ratio increased to 0.75 to 1.00 for the next four fiscal quarters; it was previously 0.65 to 1.00. Additionally, covenants within Black Hills Gas Holdings financing agreements require Black Hills Gas Holdings to maintain a consolidated debt to capitalization ratio of no more than 0.75 to 1.00.

Except as provided above, our Revolving Credit Facility, our Term Loan and the SourceGas term loan require compliance with the following financial covenant at the end of each quarter:



	As of March 31, 2016	Covenant Requirement
Recourse Leverage Ratio	71%	Less than	75%

As of March 31, 2016, we were in compliance with this covenant.

(10) LONG-TERM DEBT

Long-term debt was as follows (dollars in thousands):



	Interest Rate at
	March 31, 2016	March 31, 2016			December 31, 2015			March 31, 2015
Corporate
Remarketable junior subordinated notes due November 1, 2028	3.50%	$	299,000		$	299,000		$	—
Senior unsecured notes due January 15, 2026	3.95%	300,000			—			—
Unamortized discount on Senior unsecured notes due 2026		(892		)	—			—
Senior unsecured notes due November 30, 2023	4.25%	525,000			525,000			525,000
Unamortized discount on Senior unsecured notes due 2023		(1,822		)	(1,890		)	(2,095		)
Senior unsecured notes due July 15, 2020	5.88%	200,000			200,000			200,000
Senior unsecured notes due January 11, 2019	2.50%	250,000			—			—
Unamortized discount on Senior unsecured notes due 2019		(282		)	—			—
Corporate term loan due June 30, 2017 ^{(a) (b)}	1.38%	340,000			—			—
Corporate term loan due April 12, 2017 ^(b)	1.40%	300,000			300,000			—
Corporate term loan due June 19, 2015 ^(b)	1.31%	—			—			275,000
Total Corporate Debt		2,211,004			1,322,110			997,905

Gas Utilities
Senior secured notes due September 29, 2019 ^{(a) (e)}	3.98%	95,000			—			—
Senior unsecured notes due April 1, 2017 ^(a)	5.90%	325,000			—			—
Unamortized discount on Senior unsecured notes due 2017		(103		)	—			—
		419,897			—			—
Electric Utilities
First Mortgage Bonds due October 20, 2044	4.43%	85,000			85,000			85,000
First Mortgage Bonds due October 20, 2044	4.53%	75,000			75,000			75,000
First Mortgage Bonds due August 15, 2032	7.23%	75,000			75,000			75,000
First Mortgage Bonds due November 1, 2039	6.13%	180,000			180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039		(97		)	(99		)	(102		)
First Mortgage Bonds due November 20, 2037	6.67%	110,000			110,000			110,000
Industrial development revenue bonds due September 1, 2021 ^(c)	0.45%	7,000			7,000			7,000
Industrial development revenue bonds due March 1, 2027 ^(c)	0.47%	10,000			10,000			10,000
Series 94A Debt, variable rate due June 1, 2024 ^(c)	0.85%	2,855			2,855			2,855
Total Electric Utilities Debt		544,758			544,756			544,753

Total long-term debt		3,175,659			1,866,866			1,542,658
Less current maturities		—			—			—
Less deferred financing costs ^(d)		(16,604		)	(13,184		)	(11,286		)
Long-term debt, net of current maturities		$	3,159,055		$	1,853,682		$	1,531,372

_______________


(a)	Long-term debt assumed with the SourceGas Acquisition.


(b)	Variable interest rate, based on LIBOR plus a spread.


(c)	Variable interest rate.


(d)	Includes deferred financing costs associated with our Revolving Credit Facility of $1.6 million, $1.7 million and $1.6 million as of March 31, 2016, December 31, 2015 and March 31, 2015, respectively.


(e)	Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness.

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2016	$	—
2017	$	965,000
2018	$	—
2019	$	345,000
2020	$	200,000
Thereafter	$	1,668,855

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at March 31, 2016.

Debt Transactions

On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consisted of $300 million of 3.95%, 10-year senior notes due 2026, and $250 million of 2.50%, 3-year senior notes due 2019. After discounts and underwriter fees, net proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts will be amortized over the life of each respective note.

Assumption of Long-Term Debt

At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following:


•	$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007 due April 1, 2017.


•	$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014 due September 29, 2019.


•	$340 million unsecured corporate term loan due June 30, 2017. Interest expense under this term loan is LIBOR plus a margin of 0.875%.

(11) EQUITY

A summary of the changes in equity is as follows:



Three Months Ended March 31, 2016	Total Stockholders’ Equity
	(in thousands)
Balance at December 31, 2015	$	1,465,867
Net income (loss) available for common stock	40,002
Other comprehensive income (loss)	(11,770		)
Dividends on common stock	(21,543		)
Share-based compensation	561
Issuance of common stock	6,824
Dividend reinvestment and stock purchase plan	755
Other stock transactions	(13		)
Balance at March 31, 2016	$	1,480,683



Three Months Ended March 31, 2015	Total Stockholders’ Equity
	(in thousands)
Balance at December 31, 2014	$	1,353,884
Net income (loss) available for common stock	33,850
Other comprehensive income	990
Dividends on common stock	(18,148		)
Share-based compensation	209
Issuance of common stock	—
Dividend reinvestment and stock purchase plan	798
Other stock transactions	—
Balance at March 31, 2015	$	1,371,583

At-the-Market Equity Offering Program

On March 18, 2016, we implemented an at-the-market equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We have issued 121,000 common shares for $7.0 million, net of $0.1 million in fees and issuance costs with settlement dates through March 31, 2016 under the ATM equity offering program. Additionally, 140,000 shares for net proceeds of $8.4 million have been offered, but were not yet settled as of March 31, 2016.

(12) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2015 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to:


•	Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production; and our fuel procurement for certain of our gas-fired generation assets; and


•	Interest rate risk associated with our variable-rate debt and anticipated future refinancings.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and in Note 13.

Oil and Gas

We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss).

The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	March 31, 2016				December 31, 2015				March 31, 2015
	Crude Oil Futures, Swaps and Options		Natural Gas Futures and Swaps		Crude Oil Futures, Swaps and Options		Natural Gas Futures and Swaps		Crude Oil Futures, Swaps and Options		Natural Gas Futures and Swaps
Notional ^(a)	159,000		3,447,500		198,000		4,392,500		305,000		5,367,500
Maximum terms in months ^(b)	1		1		1		1		1		1
Derivative assets, current	$	—	$	—	$	—	$	—	$	—	$	—
Derivative assets, non-current	$	—	$	—	$	—	$	—	$	—	$	—
Derivative liabilities, current	$	—	$	—	$	—	$	—	$	—	$	—
Derivative liabilities, non-current	$	—	$	—	$	—	$	—	$	—	$	—

__________


(a)	Crude oil in Bbls, natural gas in MMBtus.


(b)	Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.

Based on March 31, 2016 prices, a $7.6 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used for Electric Utility generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, fixed to float swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss), or the Condensed Consolidated Statements of Comprehensive Income (Loss).

For hedging activities associated with our retail marketing operations, the effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income (Loss).

The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:



	March 31, 2016		December 31, 2015		March 31, 2015
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	18,270,000	57	20,580,000	60	17,280,000	69
Natural gas options purchased	990,000	21	2,620,000	3	1,320,000	12
Natural gas basis swaps purchased	16,810,000	57	18,150,000	60	15,735,000	57
Natural gas fixed for float swaps purchased ^(b)	2,374,000	23	—	0	—	0
Natural gas fixed for float swaps sold ^(b)	816,989	15	—	0	—	0
Natural gas physical purchases	2,948,250	12	—	0	—	0
Natural gas physical sales	813,200	11	—	0	—	0

__________


(a)	Term reflects the maximum forward period hedged.


(b)	1,109,500 MMBtus and 112,500 MMBtus were designated as cash flow hedges for the natural gas swaps purchased and sold, respectively.

We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands):



	March 31, 2016		December 31, 2015		March 31, 2015
Derivative assets, current	$	1,486	$	—	$	—
Derivative assets, non-current	$	85	$	—	$	—
Derivative liabilities, current	$	1,675	$	—	$	—
Derivative liabilities, non-current	$	44	$	—	$	—
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	20,324	$	23,578	$	21,606

Financing Activities

We entered into pay fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	March 31, 2016									December 31, 2015						March 31, 2015
	Interest Rate Swaps^(a)			Interest Rate Swaps^(a)			Interest Rate Swaps^(b)			Interest Rate Swaps^(a)			Interest Rate Swaps^(b)			Interest Rate Swaps^(b)
Notional	$	150,000		$	250,000		$	75,000		$	250,000		$	75,000		$	75,000
Weighted average fixed interest rate	2.09		%	2.29		%	4.97		%	2.29		%	4.97		%	4.97		%
Maximum terms in years	1.08			1.08			0.75			1.33			1.00			1.75
Derivative assets, non-current	$	—		$	—		$	—		$	3,441		$	—		$	—
Derivative liabilities, current	$	—		$	—		$	2,290		$	—		$	2,835		$	3,342
Derivative liabilities, non-current	$	3,785		$	10,693		$	—		$	—		$	156		$	2,143

__________


(a)	These swaps are designated as cash flow hedges of anticipated debt refinancings.


(b)	These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings.

Based on March 31, 2016 market interest rates and balances related to our interest rate swaps, a loss of approximately $2.3 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market interest rates change.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):



Three Months Ended March 31, 2016
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Reclassifications from AOCI into Income	Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements)		Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	$	(15,047	)	Interest expense	$	1,709		$	—
Commodity derivatives	1,589			Revenue	3,592			—
Commodity derivatives	238			Fuel, purchased power and cost of natural gas sold	57		Fuel, purchased power and cost of natural gas sold	—
Total	$	(13,220	)		$	5,358		$	—



Three Months Ended March 31, 2015
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Reclassifications from AOCI into Income	Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)
Interest rate swaps	$	(886	)	Interest expense	$	1,437			$	—
Commodity derivatives	3,764			Revenue	(3,932		)		—
Total	$	2,878			$	(2,495	)		$	—

(13) FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information see Notes 1, 8, 9 and 10 to the Consolidated Financial Statements included in our 2015 Annual Report on Form 10-K filed with the SEC.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:


•	The commodity contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure.

Utilities Segments:

•

The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter swaps, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty on a daily basis. The fair value of these swaps include a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

Corporate Activities:

•

The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that takes into account our credit ratings, and the credit rating of our counterparty.

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.



	As of March 31, 2016
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		4,668		—		(4,668		)	—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		3,761		—		(3,761		)	—
Commodity derivatives — Utilities	—		3,070		—		(1,499		)	1,571
Interest Rate Swaps	—		—		—		—			—
Total	$	—	$	11,499	$	—	$	(9,928	)	$	1,571

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$	—	$	—		$	—
Basis Swaps -- Oil	—		—		—		—			—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		250		—		(250		)	—
Commodity derivatives — Utilities	—		23,428		—		(21,709		)	1,719
Interest rate swaps	—		16,768		—		—			16,768
Total	$	—	$	40,446	$	—	$	(21,959	)	$	18,487

As of December 31, 2015

Level 1

Level 2

Level 3

Cash Collateral and Counterparty

Netting

Total

(in thousands)

Assets:

Commodity derivatives — Oil and Gas

Options -- Oil

—