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 September 30, 2015
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 October 31, 2015
Common stock, $1.00 par value	44,850,752	shares



TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	5

	Condensed Consolidated Statements of Income (Loss) - unaudited
	Three and Nine Months Ended September 30, 2015 and 2014	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
	Three and Nine Months Ended September 30, 2015 and 2014	6

	Condensed Consolidated Balance Sheets - unaudited
	September 30, 2015, December 31, 2014 and September 30, 2014	7

	Condensed Consolidated Statements of Cash Flows - unaudited
	Nine Months Ended September 30, 2015 and 2014	9

	Notes to Condensed Consolidated Financial Statements - unaudited	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	67

Item 4.	Controls and Procedures	70

PART II.	OTHER INFORMATION	71

Item 1.	Legal Proceedings	71

Item 1A.	Risk Factors	71

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	74

Item 4.	Mine Safety Disclosures	74

Item 5.	Other Information	74

Item 6.	Exhibits	74

	Signatures	76

	Index to Exhibits	77

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
Bbl	Barrel
BHC	Black Hills Corporation; the Company
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 Black Hills Utility Holdings, Inc., and its subsidiaries
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
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
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
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
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.
EPA	United States Environmental Protection Agency



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.
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.
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)
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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except per share amounts)

Revenue	$	272,105		$	272,087		$	986,346		$	1,015,493

Operating expenses:
Utilities -
Fuel, purchased power and cost of natural gas sold	71,627			84,674			350,778			416,473
Operations and maintenance	67,282			64,245			205,630			201,546
Non-regulated energy operations and maintenance	22,548			20,170			67,744			63,852
Depreciation, depletion and amortization	37,768			36,628			116,821			107,754
Taxes - property, production and severance	10,675			11,082			33,988			32,462
Impairment of long-lived assets	61,875			—			178,395			—
Other operating expenses	2,374			49			3,392			323
Total operating expenses	274,149			216,848			956,748			822,410

Operating income (loss)	(2,044		)	55,239			29,598			193,083

Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	(22,378		)	(17,919		)	(61,833		)	(53,665		)
Allowance for funds used during construction - borrowed	478			319			843			845
Capitalized interest	280			231			1,037			734
Interest income	414			575			1,163			1,541
Allowance for funds used during construction - equity	430			297			563			828
Other income (expense), net	842			261			1,568			1,262
Total other income (expense), net	(19,934		)	(16,236		)	(56,659		)	(48,455		)

Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(21,978		)	39,003			(27,061		)	144,628
Equity in earnings (loss) of unconsolidated subsidiaries	—			—			(344		)	(1		)
Impairment of equity investments	—			—			(5,170		)	—
Income tax benefit (expense)	12,035			(11,640		)	14,640			(48,272		)
Net income (loss) available for common stock	$	(9,943	)	$	27,363		$	(17,935	)	$	96,355

Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic	$	(0.22	)	$	0.62		$	(0.40	)	$	2.17
Earnings (loss) per share, Diluted	$	(0.22	)	$	0.61		$	(0.40	)	$	2.16
Weighted average common shares outstanding:
Basic	44,635			44,415			44,598			44,382
Diluted	44,635			44,608			44,598			44,584

Dividends declared per share of common stock	$	0.405		$	0.390		$	1.215		$	1.170

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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)

Net income (loss) available for common stock	$	(9,943	)	$	27,363		$	(17,935	)	$	96,355

Other comprehensive income (loss), net of tax:
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(1,609) and $(1,840) for the three months ended 2015 and 2014 and $(1,482) and $582 for the nine months ended 2015 and 2014, respectively)	2,773			3,145			2,644			(1,071		)
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $558 and $(732) for the three months ended 2015 and 2014 and $2,548 and $(1,931) for the nine months ended 2015 and 2014, respectively)	(948		)	1,328			(3,450		)	3,511
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $0 and $0 for the three months ended 2015 and 2014 and $16 and $2 for the nine months ended 2015 and 2014, respectively)	—			—			(27		)	(2		)
Benefit plan liability tax adjustments - net gain (loss)	—			—			—			(394		)
Benefit plan liability adjustments - prior service cost (net of tax (expense) benefit of $0 and $0 for the three months ended 2015 and 2014 and $0 and $(90) for the nine months ended 2015 and 2014, respectively)	—			—			—			164
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $17 for the three months ended 2015 and 2014 and $58 and $60 for the nine months ended 2015 and 2014, respectively)	(36		)	(31		)	(108		)	(110		)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(247) and $(86) for the three months ended 2015 and 2014 and $(742) and $(262) for the nine months ended 2015 and 2014, respectively)	459			160			1,374			485
Other comprehensive income (loss), net of tax	2,248			4,602			433			2,583

Comprehensive income (loss) available for common stock	$	(7,695	)	$	31,965		$	(17,502	)	$	98,938

See Note 13 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
	September 30, 2015			December 31, 2014			September 30, 2014
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	38,841		$	21,218		$	11,939
Restricted cash and equivalents	2,462			2,056			1,918
Accounts receivable, net	115,502			189,992			123,399
Materials, supplies and fuel	90,349			91,191			105,726
Derivative assets, current	—			—			—
Income tax receivable, net	—			2,053			1,268
Deferred income tax assets, net, current	47,783			48,288			34,756
Regulatory assets, current	51,962			74,396			68,444
Other current assets	55,383			24,842			26,502
Total current assets	402,282			454,036			373,952

Investments	12,148			17,294			17,144

Property, plant and equipment	4,882,420			4,563,400			4,493,696
Less: accumulated depreciation and depletion	(1,617,723		)	(1,357,929		)	(1,373,247		)
Total property, plant and equipment, net	3,264,697			3,205,471			3,120,449

Other assets:
Goodwill	359,527			353,396			353,396
Intangible assets, net	3,440			3,176			3,231
Regulatory assets, non-current	182,337			183,443			140,422
Derivative assets, non-current	—			—			—
Other assets, non-current	22,131			29,086			29,930
Total other assets, non-current	567,435			569,101			526,979

TOTAL ASSETS	$	4,246,562		$	4,245,902		$	4,038,524

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
	September 30, 2015			December 31, 2014			September 30, 2014
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	91,633		$	124,139		$	100,444
Accrued liabilities	229,957			170,115			163,374
Derivative liabilities, current	3,312			3,340			3,397
Accrued income taxes, net	308			—			—
Regulatory liabilities, current	5,647			3,687			828
Notes payable	117,900			75,000			184,000
Current maturities of long-term debt	—			275,000			275,000
Total current liabilities	448,757			651,281			727,043

Long-term debt, net of current maturities	1,567,797			1,267,589			1,107,519

Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	494,834			511,952			494,095
Derivative liabilities, non-current	722			2,680			3,273
Regulatory liabilities, non-current	152,164			145,144			118,856
Benefit plan liabilities	158,614			158,966			108,924
Other deferred credits and other liabilities	136,462			154,406			144,089
Total deferred credits and other liabilities	942,796			973,148			869,237

Commitments and contingencies (See Notes 2, 9, 10, 15, 16)

Stockholders’ equity:
Common stock equity —
Common stock $1 par value; 100,000,000 shares authorized; issued 44,891,626; 44,714,072; and 44,696,670 shares, respectively	44,892			44,714			44,697
Additional paid-in capital	753,856			748,840			746,575
Retained earnings	504,864			577,249			560,133
Treasury stock, at cost – 36,711; 42,226; and 41,552 shares, respectively	(1,789		)	(1,875		)	(1,841		)
Accumulated other comprehensive income (loss)	(14,611		)	(15,044		)	(14,839		)
Total stockholders’ equity	1,287,212			1,353,884			1,334,725

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,246,562		$	4,245,902		$	4,038,524

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)	Nine Months Ended September 30,
	2015			2014
Operating activities:	(in thousands)
Net income (loss) available for common stock	$	(17,935	)	$	96,355
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	116,821			107,754
Deferred financing cost amortization	3,074			1,608
Impairment of long-lived assets	183,565			—
Derivative fair value adjustments	(8,851		)	2,136
Stock compensation	2,868			6,978
Deferred income taxes	(20,808		)	48,930
Employee benefit plans	15,175			11,109
Other adjustments, net	4,013			2,016
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	3,618			(17,248		)
Accounts receivable, unbilled revenues and other operating assets	75,966			53,511
Accounts payable and other operating liabilities	(5,255		)	(14,307		)
Regulatory assets - current	27,768			(43,727		)
Regulatory liabilities - current	2,457			(9,845		)
Contributions to defined benefit pension plans	(10,200		)	(10,200		)
Other operating activities, net	(6,403		)	4,087
Net cash provided by (used in) operating activities	365,873			239,157

Investing activities:
Property, plant and equipment additions	(349,471		)	(290,299		)
Proceeds from sale of assets	—			22,342
Other investing activities	(7,189		)	(2,364		)
Net cash provided by (used in) investing activities	(356,660		)	(270,321		)

Financing activities:
Dividends paid on common stock	(54,450		)	(52,218		)
Common stock issued	2,484			2,393
Short-term borrowings - issuances	287,910			396,250
Short-term borrowings - repayments	(245,010		)	(294,750		)
Long-term debt - issuances	300,000			—
Long-term debt - repayments	(275,000		)	(12,200		)
Other financing activities	(7,524		)	(4,213		)
Net cash provided by (used in) financing activities	8,410			35,262
Net change in cash and cash equivalents	17,623			4,098
Cash and cash equivalents, beginning of period	21,218			7,841
Cash and cash equivalents, end of period	$	38,841		$	11,939

See Note 14 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 2014 Annual Report on Form 10-K/A)

(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 2014 Annual Report on Form 10-K/A filed with the SEC.

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Coal Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

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 September 30, 2015, December 31, 2014, and September 30, 2014 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 and nine months ended September 30, 2015 and September 30, 2014, and our financial condition as of September 30, 2015, December 31, 2014, and September 30, 2014, 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.

Recently Issued and Adopted Accounting Standards

We have implemented all new accounting pronouncements that are in effect and may impact our financial statements. We are currently assessing the impact any other new accounting pronouncements that have been issued may have on our financial position, results of operations, or cash flows.

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. Early adoption is permitted. We are currently evaluating the impact of adoption that ASU 2015-03 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, 2018 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.

Correction of Immaterial Errors

In preparing our condensed 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 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 errors identified caused an understatement of 2008, 2009, 2012 and Q1 2015 non-cash 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.

In accordance with Staff Accounting Bulletin (SAB) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, we evaluated these errors, including both qualitative and quantitative considerations, and concluded that the errors did not, individually or in the aggregate, result in a material misstatement of our previously issued condensed consolidated financial statements.

The following tables present the revisions to particular line items resulting from the corrections of these errors in this Quarterly Report on Form 10-Q. The impact of the errors relate entirely to our Oil and Gas segment.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	For the Three Months Ended September 30, 2014									For the Nine Months Ended September 30, 2014
	As Reported			Adjustments			As Revised			As Reported			Adjustments			As Revised
	(in thousands, expect per share amounts)

Depreciation, depletion and amortization	$	37,463		$	(835	)	$	36,628		$	110,258		$	(2,504	)	$	107,754
Total operating expenses	$	217,683		$	(835	)	$	216,848		$	824,914		$	(2,504	)	$	822,410

Operating income (loss)	$	54,404		$	835		$	55,239		$	190,579		$	2,504		$	193,083

Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	$	38,168		$	835		$	39,003		$	142,124		$	2,504		$	144,628
Income tax benefit (expense)	$	(11,332	)	$	(308	)	$	(11,640	)	$	(47,349	)	$	(923	)	$	(48,272	)
Net income (loss) available for common stock	$	26,836		$	527		$	27,363		$	94,774		$	1,581		$	96,355

Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic	$	0.60		$	0.02		$	0.62		$	2.14		$	0.03		$	2.17
Earnings (loss) per share, Diluted	$	0.60		$	0.01		$	0.61		$	2.13		$	0.03		$	2.16

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



	For the Three Months Ended September 30, 2014						For the Nine Months Ended September 30, 2014
(in thousands)	As Reported		Adjustments		As Revised		As Reported		Adjustments		As Revised
Net income (loss) available for common stock	$	26,836	$	527	$	27,363	$	94,774	$	1,581	$	96,355
Comprehensive income (loss)	$	31,438	$	527	$	31,965	$	97,357	$	1,581	$	98,938

CONDENSED CONSOLIDATED BALANCE SHEETS



	As of September 30, 2014
	As Reported			Adjustments			As Revised
	(in thousands)
Accumulated depreciation and depletion	$	(1,338,509	)	$	(34,738	)	$	(1,373,247	)
Total property, plant and equipment, net	$	3,155,187		$	(34,738	)	$	3,120,449
TOTAL ASSETS	$	4,073,262		$	(34,738	)	$	4,038,524

Deferred income tax liability, non-current	$	506,166		$	(12,071	)	$	494,095
Total deferred credits and other liabilities	$	881,308		$	(12,071	)	$	869,237

Retained earnings	$	582,800		$	(22,667	)	$	560,133
Total stockholders' equity	$	1,357,392		$	(22,667	)	$	1,334,725
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,073,262		$	(34,738	)	$	4,038,524

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30, 2014
	As Reported		Adjustments			As Revised
	(in thousands)
Net income (loss) available for common stock	$	94,774	$	1,581		$	96,355

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	$	110,258	$	(2,504	)	$	107,754
Deferred income taxes	$	48,007	$	923		$	48,930
Net cash provided by (used in) operating activities	$	239,157	$	—		$	239,157

The Notes to the Condensed Consolidated Financial Statements have been revised to reflect the correction of these errors for all periods presented.

(2) ACQUISITION

Acquisition of SourceGas

On July 12, 2015, Black Hills Utility Holdings entered into a definitive agreement to acquire SourceGas Holdings LLC and its subsidiaries from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE), for approximately $1.89 billion, which includes $200 million of projected capital expenditures through closing and the assumption of $700 million in debt projected at closing. The effective purchase price is estimated to be $1.74 billion after taking into account approximately $150 million of future tax benefits associated with acquired NOLs and the step up in certain assets including goodwill resulting from the transaction. The purchase price is subject to customary post-closing adjustments for cash, capital expenditures, indebtedness and working capital. In conjunction with the agreement, we entered into a commitment letter for a one-year, $1.17 billion senior unsecured fully-committed bridge facility provided by Credit Suisse, subsequently replaced on August 6, 2015 by the Bridge Term Loan Agreement discussed below.

We expect to finance the acquisition with equity proceeds of $450 million to $600 million, including $200 million to $300 million of unit mandatory convertibles, $450 million to $550 million of new long-term indebtedness, and assuming approximately $700 million of continuing debt of SourceGas, with the remainder funded from cash on hand and draws under our revolving credit agreement.

SourceGas primarily operates four regulated natural gas utilities serving approximately 425,000 customers in Arkansas, Colorado, Nebraska and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado. Following completion of the transaction, SourceGas will be a wholly-owned subsidiary of Black Hills Utility Holdings.

The agreement for the acquisition of SourceGas is subject to various provisions including representations, warranties, and covenants with respect to Arkansas, Colorado, Nebraska and Wyoming utility businesses that are subject to customary conditions and limitations. Completion of the transaction is also subject to regulatory approvals from the APSC, CPUC, NPSC and WPSC, and was also subject to notification, clearance and reporting requirements under the Hart-Scott-Rodino Act, which waiting period expired on August 18, 2015. On August 10, 2015, we filed joint applications with the APSC, CPUC, NPSC and WPSC, requesting a March 1, 2016 approval date in all four filings. The discovery process with all four state commissions is ongoing and the acquisition is expected to close during the first half of 2016.

BHC has guaranteed the full and complete payment and performance of Black Hills Utility Holdings.

Effective August 6, 2015, we entered into a Bridge Term Loan Agreement with Credit Suisse as the Administrative Agent and 10 additional banks, collectively, for commitments totaling $1.17 billion pursuant to the previously executed bridge commitment letter with Credit Suisse. We may draw up to $1.17 billion on this loan to fund the SourceGas Acquisition and related expenses. The Agreement contains the same customary affirmative and negative covenants as contained in our Revolving Credit Agreement and Term Loan Credit Agreement, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintaining a recourse leverage ratio not to exceed 0.75 to 1. In the event we fund under the Bridge Term Loan Agreement, in certain circumstances, we are required to pay down those borrowings with funds received from the proceeds of equity and debt offerings and asset sales. Additionally, our Revolving Credit Facility and Term Loan Credit Agreements were amended in connection with the Bridge Term Loan Agreement to permit the assumption of certain indebtedness of SourceGas and to increase the Recourse Leverage Ratio in certain circumstances. In these amendments, the maximum Recourse Ratio is no greater than 0.65 to 1 at the end of any fiscal quarter, but may increase to (i) 0.70 to 1 at the end of any fiscal quarter during such four fiscal quarter period where the aggregate outstanding debt assumed or incurred in connection with our acquisition of SourceGas is equal to or greater than $1.25 billion and less than $1.46 billion or (ii) 0.75 to 1 at the end of any fiscal quarter during such four fiscal quarter period that the aggregate outstanding debt assumed or incurred in connection with our acquisition of SourceGas is equal to or greater than $1.46 billion.

(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 September 30, 2015	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss)
Utilities:
Electric	$	182,263	$	2,547		$	21,982
Gas	68,934		—			1,630
Non-regulated Energy:
Power Generation	2,123		21,128			9,067
Coal Mining	8,890		8,076			3,047
Oil and Gas ^(a)	9,895		—			(39,769		)
Corporate activities^(c)	—		—			(5,900		)
Inter-company eliminations	—		(31,751		)	—
Total	$	272,105	$	—		$	(9,943	)



Three Months Ended September 30, 2014	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss)
Utilities:
Electric	$	171,395	$	3,156		$	18,154
Gas	78,735		—			1,597
Non-regulated Energy:
Power Generation	1,602		20,419			7,829
Coal Mining	6,884		8,689			2,638
Oil and Gas	13,471		—			(2,583		)
Corporate activities	—		—			(272		)
Inter-company eliminations	—		(32,264		)	—
Total	$	272,087	$	—		$	27,363




Nine Months Ended September 30, 2015	External Operating Revenues		Inter-company Operating Revenue			Net Income (Loss)
Utilities:
Electric	$	534,988	$	8,480		$	58,613
Gas	386,011		—			27,007
Non-regulated Energy:
Power Generation	5,782		62,452			24,761
Coal Mining	26,084		23,541			9,106
Oil and Gas ^(a)(b)	33,481		—			(130,079		)
Corporate activities ^(c)	—		—			(7,343		)
Inter-company eliminations	—		(94,473		)	—
Total	$	986,346	$	—		$	(17,935	)




Nine Months Ended September 30, 2014	External Operating Revenues		Inter-company Operating Revenue			Net Income (Loss)
Utilities:
Electric	$	508,230	$	10,307		$	44,156
Gas	440,571		—			28,289
Non-regulated Energy:
Power Generation	4,138		62,211			23,096
Coal Mining	19,085		26,637			7,118
Oil and Gas	43,469		—			(5,211		)
Corporate activities	—		—			(1,093		)
Inter-company eliminations	—		(99,155		)	—
Total	$	1,015,493	$	—		$	96,355

__________


(a)	Net income (loss) for the three and nine months ended September 30, 2015 included non-cash after-tax ceiling test impairments of $36 million and $113 million, respectively. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


(b)	Net income (loss) for the nine months ended September 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(c) Net income (loss) for the three and nine months ended September 30, 2015 included incremental, non-recurring acquisition costs, net of tax of $2.8 million and $3.0 million, respectively and after-tax internal labor costs attributable to the acquisition of $1.2 million and $1.8 million, respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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:	September 30, 2015		December 31, 2014		September 30, 2014
Utilities:
Electric ^(a)	$	2,846,931	$	2,748,680	$	2,671,601
Gas	831,802		906,922		827,069
Non-regulated Energy:
Power Generation^(a)	78,666		76,945		64,359
Coal Mining	78,000		74,407		74,130
Oil and Gas ^{(b) (c)}	280,842		332,343		296,043
Corporate activities	130,321		106,605		105,322
Total assets	$	4,246,562	$	4,245,902	$	4,038,524

__________


(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)	As a result of continued low commodity prices during 2015, we recorded non-cash impairments of oil and gas assets included in our Oil and Gas segment of $62 million and $178 million for the for the three and nine months ended September 30, 2015, respectively. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


(c)	Includes a non-cash impairment of our Oil and Gas equity investments of $5.2 million for the nine months ended September 30, 2015. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

(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
September 30, 2015	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	43,337	$	35,069	$	(720	)	$	77,686
Gas Utilities	18,349		10,140		(618		)	27,871
Power Generation	1,186		—		—			1,186
Coal Mining	2,684		—		—			2,684
Oil and Gas	4,522		—		(13		)	4,509
Corporate	1,566		—		—			1,566
Total	$	71,644	$	45,209	$	(1,351	)	$	115,502



	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2014	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	59,714	$	26,474	$	(722	)	$	85,466
Gas Utilities	47,394		45,546		(781		)	92,159
Power Generation	1,369		—		—			1,369
Coal Mining	3,151		—		—			3,151
Oil and Gas	5,305		—		(13		)	5,292
Corporate	2,555		—		—			2,555
Total	$	119,488	$	72,020	$	(1,516	)	$	189,992



	Accounts		Unbilled		Less Allowance for			Accounts
September 30, 2014	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	53,717	$	21,485	$	(724	)	$	74,478
Gas Utilities	23,409		13,218		(740		)	35,887
Power Generation	1,368		—		—			1,368
Coal Mining	2,563		—		—			2,563
Oil and Gas	7,657		—		(13		)	7,644
Corporate	1,459		—		—			1,459
Total	$	90,173	$	34,703	$	(1,477	)	$	123,399

(5) REGULATORY ACCOUNTING

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



	Maximum	As of		As of		As of
	Amortization (in years)	September 30, 2015		December 31, 2014		September 30, 2014
Regulatory assets
Deferred energy and fuel cost adjustments - current^{(a) (d)}	1	$	25,354	$	23,820	$	26,211
Deferred gas cost adjustments ^(a)(d)	2	9,358		37,471		42,400
Gas price derivatives ^(a)	7	23,681		18,740		7,470
AFUDC^(b)	45	12,580		12,358		12,411
Employee benefit plans ^{(c) (e)}	12	95,779		97,126		64,908
Environmental^(a)	subject to approval	1,209		1,314		1,314
Asset retirement obligations^(a)	44	675		3,287		3,282
Bond issue cost^(a)	23	3,169		3,276		3,311
Renewable energy standard adjustment ^(b)	5	5,102		9,622		12,007
Flow through accounting^(c)	35	28,585		25,887		25,157
Decommissioning costs ^(f)	10	16,353		12,484		—
Other regulatory assets^(a)	15	12,454		12,454		10,395
		$	234,299	$	257,839	$	208,866

Regulatory liabilities
Deferred energy and gas costs^{(a) (d)}	1	$	9,899	$	6,496	$	5,535
Employee benefit plans^{(c) (e)}	12	53,140		53,139		34,409
Cost of removal^(a)	44	86,946		78,249		71,362
Other regulatory liabilities^(c)	25	7,826		10,947		8,378
		$	157,811	$	148,831	$	119,684

__________


(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. Fluctuations in deferred gas cost adjustments compared to the same period in the prior year are primarily due to higher natural gas prices driven by demand and market conditions from the peak winter heating season in the first part of 2014. 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 September 30, 2014 was driven by a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.


(f)	Black Hills Power 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.

(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:



	September 30, 2015		December 31, 2014		September 30, 2014
Materials and supplies	$	53,838	$	49,555	$	52,682
Fuel - Electric Utilities	6,139		6,637		7,108
Natural gas in storage held for distribution	30,372		34,999		45,936
Total materials, supplies and fuel	$	90,349	$	91,191	$	105,726

(7) GOODWILL

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



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at December 31, 2014	$	250,487	$	94,144	$	8,765	$	353,396
Additions ^(a)	6,131		—		—		6,131
Ending balance at September 30, 2015	$	256,618	$	94,144	$	8,765	$	359,527

__________


(a)	Goodwill was recorded on the acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. completed on July 1, 2015.

(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 September 30,					Nine Months Ended September 30,
	2015			2014		2015			2014

Net income (loss) available for common stock	$	(9,943	)	$	27,363	$	(17,935	)	$	96,355

Weighted average shares - basic	44,635			44,415		44,598			44,382
Dilutive effect of:
Equity compensation	—			193		—			202
Weighted average shares - diluted	44,635			44,608		44,598			44,584

Due to our net loss for the three and nine months ended September 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 58,380 and 82,130 equity compensation shares were excluded from the computations for the three and nine months ended September 30, 2015, respectively.

In addition to these potentially dilutive shares excluded due to our net loss for the three and nine months ended September 30, 2015, the following outstanding securities were also excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014

Equity compensation	121	99	114	75
Anti-dilutive shares	121	99	114	75

(9) NOTES PAYABLE AND LONG-TERM DEBT

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



	September 30, 2015				December 31, 2014				September 30, 2014
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	117,900	$	30,600	$	75,000	$	35,000	$	184,000	$	31,726

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 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 September 30, 2015. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating.

Replacement of Corporate Term Loan

On April 13, 2015, we entered into a new $300 million Corporate term loan expiring April 12, 2017. This new term loan replaced the $275 million Corporate term loan due on June 19, 2015 and was classified as Long-Term Debt as of September 30, 2015. The additional $25 million, less interest and fees, was used for general corporate purposes. The cost of the borrowing under the new term loan is LIBOR plus a margin of 0.9%. The covenants on the new term loan are substantially the same as the Revolving Credit Facility.

Debt Covenants

On August 6, 2015, in connection with the Bridge Term Loan Agreement as 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 in certain circumstances. In these amendments, the maximum Recourse Ratio is no greater than 0.65 to 1 at the end of any fiscal quarter, but may increase to (i) 0.70 to 1 at the end of any fiscal quarter during such four fiscal quarter period where the aggregate outstanding debt assumed or incurred in connection with our acquisition of SourceGas is equal to or greater than $1.25 billion and less than $1.46 billion or (ii) 0.75 to 1 at the end of any fiscal quarter during such four fiscal quarter period that the aggregate outstanding debt assumed or incurred in connection with our acquisition of SourceGas is equal to or greater than $1.46 billion.

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



	As of September 30, 2015	Covenant Requirement
Recourse Leverage Ratio	58%	Less than	65%

As of September 30, 2015, we were in compliance with this covenant.

(10) 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 2014 Annual Report on Form 10-K/A.

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.

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 upon 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 11.

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:



	September 30, 2015				December 31, 2014				September 30, 2014
	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)	258,000		5,392,500		334,500		6,582,500		391,500		7,930,000
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 September 30, 2015 prices, an $8.8 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 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. 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).

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



	September 30, 2015		December 31, 2014		September 30, 2014
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	17,180,000	63	19,370,000	72	16,290,000	74
Natural gas options purchased	6,300,000	6	4,020,000	8	7,070,000	6
Natural gas basis swaps purchased	12,980,000	51	12,005,000	60	12,025,000	63

__________


(a)	Term reflects the maximum forward period hedged.

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



	September 30, 2015		December 31, 2014		September 30, 2014
Derivative assets, current	$	—	$	—	$	—
Derivative assets, non-current	$	—	$	—	$	—
Derivative liabilities, non-current	$	—	$	—	$	—
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	23,678	$	18,740	$	7,470

Financing Activities

We entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. 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:



	September 30, 2015			December 31, 2014			September 30, 2014
	Interest Rate Swaps^(a)			Interest Rate Swaps^(a)			Interest Rate Swaps^(a)
Notional	$	75,000		$	75,000		$	75,000
Weighted average fixed interest rate	4.97		%	4.97		%	4.97		%
Maximum terms in years	1.33			2.00			2.25
Derivative liabilities, current	$	3,312		$	3,340		$	3,397
Derivative liabilities, non-current	$	722		$	2,680		$	3,273

__________


(a)	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 September 30, 2015 market interest rates and balances related to our interest rate swaps, a loss of approximately $3.3 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 September 30, 2015
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			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	$	(898	)	Interest expense	$	(1,603	)		$	—
Commodity derivatives	5,280			Revenue	3,109				—
Total	$	4,382			$	1,506			$	—



Three Months Ended September 30, 2014
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			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	$	152	Interest expense	$	(925	)		$	—
Commodity derivatives	4,833		Revenue	(1,135		)		—
Total	$	4,985		$	(2,060	)		$	—




Nine Months Ended September 30, 2015
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			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	$	(2,674	)	Interest expense	$	(4,709	)		$	—
Commodity derivatives	6,800			Revenue	10,707				—
Total	$	4,126			$	5,998			$	—




Nine Months Ended September 30, 2014
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)			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	$	(277	)	Interest expense	$	(2,745	)		$	—
Commodity derivatives	(1,376		)	Revenue	(2,697		)		—
Total	$	(1,653	)		$	(5,442	)		$	—

(11) 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 2014 Annual Report on Form 10-K/A 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 and basis swaps (Level 2) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract.

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 our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

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 our 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 September 30, 2015
	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	—		6,642		—		(6,642		)	—
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		4,622		—		(4,622		)	—
Commodity derivatives — Utilities	—		3,123		—		(3,123		)	—
Total	$	—	$	14,387	$	—	$	(14,387	)	$	—

Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	—	$