BKH 10Q Q2 2015


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 June 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 July 31, 2015
Common stock, $1.00 par value
44,834,944

shares





TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income (Loss) - unaudited
 
 
 
   Three and Six Months Ended June 30, 2015 and 2014
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three and Six Months Ended June 30, 2015 and 2014
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2015, December 31, 2014 and June 30, 2014
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2015 and 2014
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements - unaudited
 
 
 
 
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 
 
 
 
 
 
Index to Exhibits
 


2


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.
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 announced in 2014 and closed on July 1, 2015.
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse Gases

3


GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of natural gas and certain services through to customers.
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 announced in 2014 that closed on January 1, 2015.
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
MW
Megawatts
MWh
Megawatt-hours
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
PPA
Power Purchase Agreement
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

4




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2015
2014
2015
2014
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
272,254

$
283,237

$
714,241

$
743,406

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of natural gas sold
73,824

101,331

279,151

331,799

Operations and maintenance
67,264

66,074

138,348

137,301

Non-regulated energy operations and maintenance
23,146

21,350

45,196

43,682

Depreciation, depletion and amortization
40,051

35,877

79,053

71,126

Taxes - property, production and severance
11,377

11,044

23,313

21,380

Impairment of long-lived assets
94,484

—

116,520

—

Other operating expenses
966

149

1,018

274

Total operating expenses
311,112

235,825

682,599

605,562

 
 
 
 
 
Operating income (loss)
(38,858
)
47,412

31,642

137,844

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(19,545
)
(17,886
)
(39,455
)
(35,746
)
Allowance for funds used during construction - borrowed
207

256

365

526

Capitalized interest
481

246

757

503

Interest income
301

576

749

966

Allowance for funds used during construction - equity
77

293

133

531

Other income (expense), net
395

409

726

1,000

Total other income (expense), net
(18,084
)
(16,106
)
(36,725
)
(32,220
)
 
 
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
(56,942
)
31,306

(5,083
)
105,624

Equity in earnings (loss) of unconsolidated subsidiaries
(47
)
—

(344
)
—

Impairment of equity investments
(5,170
)
—

(5,170
)
—

Income tax benefit (expense)
20,317

(10,959
)
2,605

(36,632
)
Net income (loss) available for common stock
$
(41,842
)
$
20,347

$
(7,992
)
$
68,992

 
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
 
Earnings (loss) per share, Basic
$
(0.94
)
$
0.46

$
(0.18
)
$
1.56

Earnings (loss) per share, Diluted
$
(0.94
)
$
0.46

$
(0.18
)
$
1.55

Weighted average common shares outstanding:
 
 
 
 
Basic
44,617

44,399

44,579

44,365

Diluted
44,617

44,588

44,579

44,571

 
 
 
 
 
Dividends declared per share of common stock
$
0.405

$
0.390

$
0.810

$
0.780


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

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2015
2014
2015
2014
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
(41,842
)
$
20,347

$
(7,992
)
$
68,992

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $1,171and $1,115 for the three months ended 2015 and 2014 and $128 and $2,422 for the six months ended 2015 and 2014, respectively)
(1,966
)
(1,959
)
(130
)
(4,216
)
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $735 and $(774) for the three months ended 2015 and 2014 and $1,989 and $(1,199) for the six months ended 2015 and 2014, respectively)
(1,261
)
1,403

(2,502
)
2,183

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 $15 and $2 for the six months ended 2015 and 2014, respectively)
—

—

(27
)
(2
)
Benefit plan liability tax adjustments - net gain (loss)
—

(394
)
—

(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 six months ended 2015 and 2014, respectively)
—

—

—

164

Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $39 for the three months ended 2015 and 2014 and $38 and $43 for the six months ended 2015 and 2014, respectively)
(36
)
(70
)
(72
)
(79
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(247) and $(91) for the three months ended 2015 and 2014 and $(494) and $(176) for the six months ended 2015 and 2014, respectively)
458

168

916

325

Other comprehensive income (loss), net of tax
(2,805
)
(852
)
(1,815
)
(2,019
)
 
 
 
 
 
Comprehensive income (loss) available for common stock
$
(44,647
)
$
19,495

$
(9,807
)
$
66,973


See Note 12 for additional disclosures.

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

6


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
As of
 
June 30,
2015
 
December 31, 2014
 
June 30,
2014
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
87,210

 
$
21,218

 
$
14,697

Restricted cash and equivalents
2,316

 
2,056

 
2

Accounts receivable, net
123,661

 
189,992

 
135,145

Materials, supplies and fuel
73,749

 
91,191

 
81,164

Derivative assets, current
—

 
—

 
1,737

Income tax receivable, net
770

 
2,053

 
1,043

Deferred income tax assets, net, current
52,394

 
48,288

 
23,872

Regulatory assets, current
47,157

 
74,396

 
64,735

Other current assets
51,315

 
24,842

 
21,660

Total current assets
438,572

 
454,036

 
344,055

 
 
 
 
 
 
Investments
12,098

 
17,294

 
17,096

 
 
 
 
 
 
Property, plant and equipment
4,726,478

 
4,563,400

 
4,408,291

Less: accumulated depreciation and depletion
(1,522,969
)
 
(1,357,929
)
 
(1,361,233
)
Total property, plant and equipment, net
3,203,509

 
3,205,471

 
3,047,058

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,211

 
3,176

 
3,286

Regulatory assets, non-current
180,815

 
183,443

 
138,226

Other assets, non-current
28,670

 
29,086

 
31,808

Total other assets, non-current
566,092

 
569,101

 
526,716

 
 
 
 
 
 
TOTAL ASSETS
$
4,220,271

 
$
4,245,902

 
$
3,934,925


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

7


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
June 30,
2015
 
December 31, 2014
 
June 30,
2014
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
78,021

 
$
124,139

 
$
100,098

Accrued liabilities
160,528

 
170,115

 
141,177

Derivative liabilities, current
3,289

 
3,340

 
3,480

Regulatory liabilities, current
10,910

 
3,687

 
828

Notes payable
105,760

 
75,000

 
132,700

Current maturities of long-term debt
—

 
275,000

 
275,000

Total current liabilities
358,508

 
651,281

 
653,283

 
 
 
 
 
 
Long-term debt, net of current maturities
1,567,727

 
1,267,589

 
1,121,950

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
510,435

 
511,952

 
463,680

Derivative liabilities, non-current
1,433

 
2,680

 
4,251

Regulatory liabilities, non-current
150,835

 
145,144

 
119,462

Benefit plan liabilities
165,791

 
158,966

 
116,403

Other deferred credits and other liabilities
154,656

 
154,406

 
137,765

Total deferred credits and other liabilities
983,150

 
973,148

 
841,561

 
 
 
 
 
 
Commitments and contingencies (See Notes 2, 8, 9, 14, 15)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,871,771; 44,714,072; and 44,682,885 shares, respectively
44,872

 
44,714

 
44,683

Additional paid-in capital
751,679

 
748,840

 
744,505

Retained earnings
532,965

 
577,249

 
550,185

Treasury stock, at cost – 35,855; 42,226; and 40,951 shares, respectively
(1,771
)
 
(1,875
)
 
(1,801
)
Accumulated other comprehensive income (loss)
(16,859
)
 
(15,044
)
 
(19,441
)
Total stockholders’ equity
1,310,886

 
1,353,884

 
1,318,131

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
4,220,271

 
$
4,245,902

 
$
3,934,925


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

8


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Six Months Ended June 30,
 
2015
2014
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
(7,992
)
$
68,992

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
79,053

71,126

Deferred financing cost amortization
1,119

1,107

Impairment of long-lived assets
121,690

—

Derivative fair value adjustments
(5,249
)
(1,660
)
Stock compensation
3,098

6,908

Deferred income taxes
(6,277
)
36,129

Employee benefit plans
10,467

7,409

Other adjustments, net
3,720

1,481

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
20,218

7,314

Accounts receivable, unbilled revenues and other operating assets
63,172

47,598

Accounts payable and other operating liabilities
(66,294
)
(24,978
)
Regulatory assets - current
27,178

(43,604
)
Regulatory liabilities - current
7,290

(9,845
)
Other operating activities, net
3,215

5,858

Net cash provided by (used in) operating activities
254,408

173,835

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(206,472
)
(177,302
)
Other investing activities
(652
)
(2,994
)
Net cash provided by (used in) investing activities
(207,124
)
(180,296
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(36,292
)
(34,803
)
Common stock issued
1,702

1,693

Short-term borrowings - issuances
154,460

214,100

Short-term borrowings - repayments
(123,700
)
(163,900
)
Long-term debt - issuances
300,000

—

Long-term debt - repayments
(275,000
)
—

Other financing activities
(2,462
)
(3,773
)
Net cash provided by (used in) financing activities
18,708

13,317

Net change in cash and cash equivalents
65,992

6,856

Cash and cash equivalents, beginning of period
21,218

7,841

Cash and cash equivalents, end of period
$
87,210

$
14,697


See Note 13 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.

9


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 June 30, 2015, December 31, 2014, and June 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 price. 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 six months ended June 30, 2015 and June 30, 2014, and our financial condition as of June 30, 2015, December 31, 2014, and June 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.


10


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 the our oil and gas properties exceeded the ceiling. Specifically, the errors related to evaluating and correctly accounting for the treatment of tax related amounts associated with the calculation. The errors identified caused an understatement of 2008, 2009, 2012 and Q1 2015 noncash ceiling test impairment calculations, which resulted in an overstatement of depletion expense from 2009 through March 31, 2015, and an understatement of the 2012 gain on sale of oil and gas properties.
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 June 30, 2014
 
For the Six Months Ended June 30, 2014
 
As Reported
Adjustments
As Revised
 
As Reported
Adjustments
As Revised
 
(in thousands expect per share amounts)
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
$
36,712

$
(835
)
$
35,877

 
$
72,795

$
(1,669
)
$
71,126

Total operating expenses
$
236,660

$
(835
)
$
235,825

 
$
607,231

$
(1,669
)
$
605,562

 
 
 
 
 
 
 
 
Operating income (loss)
$
46,577

$
835

$
47,412

 
$
136,175

$
1,669

$
137,844

 
 
 
 
 
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
$
30,471

$
835

$
31,306

 
$
103,955

$
1,669

$
105,624

Income tax benefit (expense)
$
(10,651
)
$
(308
)
$
(10,959
)
 
$
(36,017
)
$
(615
)
$
(36,632
)
Net income (loss) available for common stock
$
19,820

$
527

$
20,347

 
$
67,938

$
1,054

$
68,992

 
 
 
 
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
 
 
 
 
Earnings (loss) per share, Basic
$
0.45

$
0.01

$
0.46

 
$
1.53

$
0.03

$
1.56

Earnings (loss) per share, Diluted
$
0.44

$
0.02

$
0.46

 
$
1.52

$
0.03

$
1.55



11



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
For the Three Months Ended June 30, 2014
 
For the Six Months Ended June 30, 2014
(in thousands)
As Reported
Adjustments
As Revised
 
As Reported
Adjustments
As Revised
Net income (loss) available for common stock
$
19,820

$
527

$
20,347

 
$
67,938

$
1,054

$
68,992

Comprehensive income (loss)
$
18,968

$
527

$
19,495

 
$
65,919

$
1,054

$
66,973


CONDENSED CONSOLIDATED BALANCE SHEET
 
As of June 30, 2014
 
As Reported
Adjustments
As Revised
 
(in thousands)
Accumulated depreciation and depletion
$
(1,325,660
)
$
(35,573
)
$
(1,361,233
)
Total property, plant and equipment, net
$
3,082,631

$
(35,573
)
$
3,047,058

TOTAL ASSETS
$
3,970,498

$
(35,573
)
$
3,934,925

 
 
 
 
Deferred income tax liability, non-current
$
476,059

$
(12,379
)
$
463,680

Total deferred credits and other liabilities
$
853,940

$
(12,379
)
$
841,561

 
 
 
 
Retained earnings
$
573,379

$
(23,194
)
$
550,185

Total stockholders' equity
$
1,341,325

$
(23,194
)
$
1,318,131

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
3,970,498

$
(35,573
)
$
3,934,925


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Six Months Ended June 30, 2014
 
As Reported
Adjustments
As Revised
 
(in thousands)
Net income (loss) available for common stock
$
67,938

$
1,054

$
68,992

 
 
 
 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
$
72,795

$
(1,669
)
$
71,126

Deferred income taxes
$
35,514

$
615

$
36,129

Net cash provided by (used in) operating activities
$
173,835

$
—

$
173,835


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



12




(2)    SUBSEQUENT EVENT

Acquisition of SourceGas

On July 12, 2015, Black Hills Utility Holdings entered in 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 $720 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 tax benefits consisting of acquired NOLs and goodwill tax benefits 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 have entered into a commitment letter for a one-year, $1.17 billion senior unsecured fully committed bridge facility to be provided by Credit Suisse.

We expect to finance the acquisition with the aforementioned $720 million of assumed debt, $450 million to $550 million of new debt, $575 million to $675 million of equity and equity-linked securities, and the remainder with cash on hand and Revolver draws.

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 is also subject to notification, clearance and reporting requirements under the Hart-Scott-Rodino Act. 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 6th, 2015, we entered into a Bridge Term Loan Agreement with Credit Suisse as the Administrate Agent and 10 additional banks, collectively, for commitments totaling $1.17 billion billion pursuant to the previously executed bridge commitment letter with Credit Suisse.   We may draw up to $1.17 billion billion on this loan to fund the SourceGas Acquisition and related expenses. The Agreement contains the same customary affirmative and negative covenants as are in our Revolving Credit Agreement and Term Loan 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 Loan Credit 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 billion and less than $1.46 billion 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.


13


(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 June 30, 2015
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
169,751

 
$
2,509

 
$
17,702

   Gas
 
79,426

 
—

 
3,165

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,706

 
20,603

 
7,549

   Coal Mining
 
9,052

 
7,673

 
3,049

   Oil and Gas (a)(b)
 
12,319

 
—

 
(71,195
)
Corporate activities (c)
 
—

 
—

 
(2,112
)
Inter-company eliminations
 
—

 
(30,785
)
 
—

Total
 
$
272,254

 
$
—

 
$
(41,842
)

Three Months Ended June 30, 2014
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
158,740

 
$
3,144

 
$
11,427

   Gas
 
102,499

 
—

 
1,994

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,267

 
20,713

 
7,194

   Coal Mining
 
5,583

 
9,068

 
2,016

   Oil and Gas
 
15,148

 
—

 
(1,133
)
Corporate activities
 
—

 
—

 
(1,151
)
Inter-company eliminations
 
—

 
(32,925
)
 
—

Total
 
$
283,237

 
$
—

 
$
20,347


 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
External
Operating
Revenues
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
352,725

 
$
5,933

 
$
36,631

   Gas
 
317,077

 
—

 
25,377

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
3,659

 
41,324

 
15,694

   Coal Mining
 
17,194

 
15,465

 
6,059

   Oil and Gas (a)(b)
 
23,586

 
—

 
(90,310
)
Corporate activities (c)
 
—

 
—

 
(1,443
)
Inter-company eliminations
 
—

 
(62,722
)
 
—

Total
 
$
714,241

 
$
—

 
$
(7,992
)

14


 
 
 
 
 
 
 
Six Months Ended June 30, 2014
 
External
Operating
Revenues
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
336,835

 
$
7,151

 
$
26,002

   Gas
 
361,836

 
—

 
26,692

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
2,536

 
41,792

 
15,267

   Coal Mining
 
12,201

 
17,948

 
4,480

   Oil and Gas
 
29,998

 
—

 
(2,628
)
Corporate activities
 
—

 
—

 
(821
)
Inter-company eliminations
 
—

 
(66,891
)
 
—

Total
 
$
743,406

 
$
—

 
$
68,992

__________
(a)
Net income (loss) for the three and six months ended June 30, 2015 included non-cash after-tax ceiling test impairments of $63 million and $77 million, respectively. See Note 16 to the Condensed Consolidated Financial statements in this Quarterly Report on Form 10-Q.
(b)
Net income (loss) for the three and six months ended June 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million. See Note 16 to the Condensed Consolidated Financial statements in this Quarterly Report on Form 10-Q.
(c) Net income (loss) for the three and six months ended June 30, 2015 included acquisition costs, net of tax of $0.5 million and $0.3 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:
June 30, 2015
 
December 31, 2014
 
June 30, 2014
Utilities:
 
 
 
 
 
   Electric (a)
$
2,856,903

 
$
2,748,680

 
$
2,603,900

   Gas
801,295

 
906,922

 
799,365

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
72,270

 
76,945

 
85,269

   Coal Mining
76,079

 
74,407

 
73,701

   Oil and Gas (b) (c)
275,068

 
332,343

 
272,264

Corporate activities
138,656

 
106,605

 
100,426

Total assets
$
4,220,271

 
$
4,245,902

 
$
3,934,925

__________
(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 $94 million and $117 million for the for the three and six months ended June 30, 2015, respectively. See Note 16 to the Condensed Consolidated Financial statements in this Quarterly Report on Form 10-Q.
(c)
Includes a noncash impairment of our Oil and Gas equity investments of $5.2 million for the three and six months ended June 30, 2015.


15




(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
June 30, 2015
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
46,381

$
33,501

$
(685
)
$
79,197

Gas Utilities
25,635

9,418

(1,259
)
33,794

Power Generation
1,199

—

—

1,199

Coal Mining
3,402

—

—

3,402

Oil and Gas
5,099

—

(13
)
5,086

Corporate
983

—

—

983

Total
$
82,699

$
42,919

$
(1,957
)
$
123,661


 
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
June 30, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
48,333

$
21,716

$
(622
)
$
69,427

Gas Utilities
43,104

9,265

(1,027
)
51,342

Power Generation
1,388

—

—

1,388

Coal Mining
1,866

—

—

1,866

Oil and Gas
9,123

—

(13
)
9,110

Corporate
2,012

—

—

2,012

Total
$
105,826

$
30,981

$
(1,662
)
$
135,145



16


(5)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization (in years)
June 30, 2015
December 31, 2014
June 30, 2014
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a) (d)
1
$
26,862

$
23,820

$
29,605

Deferred gas cost adjustments (a)(d)
2
5,588

37,471

35,479

Gas price derivatives (a)
7
17,907

18,740

3,561

AFUDC (b)
45
12,321

12,358

12,468

Employee benefit plans (c) (e)
12
96,734

97,126

65,874

Environmental (a)
subject to approval
1,224

1,314

1,314

Asset retirement obligations (a)
44
3,242

3,287

3,278

Bond issue cost (a)
23
3,204

3,276

3,347

Renewable energy standard adjustment (a)
5
5,629

9,622

14,501

Flow through accounting (c)
35
27,861

25,887

22,754

Decommissioning costs (f)
10
14,845

12,484

—

Other regulatory assets (a)
15
12,555

12,454

10,780

 
 
$
227,972

$
257,839

$
202,961

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a) (d)
1
$
16,114

$
6,496

$
6,490

Employee benefit plans (c) (e)
12
53,163

53,139

34,356

Cost of removal (a)
44
84,118

78,249

70,841

Other regulatory liabilities (c)
25
8,350

10,947

8,603

 
 
$
161,745

$
148,831

$
120,290

__________
(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 June 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 $12 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:
 
June 30, 2015
 
December 31, 2014
 
June 30, 2014
Materials and supplies
$
54,646

 
$
49,555

 
$
51,925

Fuel - Electric Utilities
6,644

 
6,637

 
7,679

Natural gas in storage held for distribution
12,459

 
34,999

 
21,560

Total materials, supplies and fuel
$
73,749

 
$
91,191

 
$
81,164


17




(7)    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 June 30,
 
Six Months Ended June 30,
 
2015
2014
 
2015
2014
 
 
 
 
 
 
Net income (loss) available for common stock
$
(41,842
)
$
20,347

 
$
(7,992
)
$
68,992

 
 
 
 
 
 
Weighted average shares - basic
44,617

44,399

 
44,579

44,365

Dilutive effect of:
 
 
 
 
 
Equity compensation
—

189

 
—

206

Weighted average shares - diluted
44,617

44,588

 
44,579

44,571


The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive.

Due to our net loss the for the three and six months ended June 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, 83,613 and 101,146 equity compensation shares were excluded from the computations for the three and six months ended June 30, 2015, respectively.

In addition to these potentially dilutive shares excluded due to our net loss for the three and six months ended June 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 June 30,
 
Six Months Ended June 30,
 
2015
2014
 
2015
2014
 
 
 
 
 
 
Equity compensation
119

81

 
113

63

Anti-dilutive shares
119

81

 
113

63



18



(8)    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:
 
June 30, 2015
December 31, 2014
June 30, 2014
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
105,760

$
23,100

$
75,000

$
35,000

$
132,700

$
20,272


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 June 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 June 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

Our Revolving Credit Facility and our Term Loan require compliance with the following financial covenant at the end of each quarter:
 
As of June 30, 2015
 
Covenant Requirement
Recourse Leverage Ratio
57%
 
Less than
65%

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

(9)    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.


19


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 10.

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:
 
June 30, 2015
 
December 31, 2014
 
June 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)
276,000

4,187,500

 
334,500

6,582,500

 
424,500

9,265,000

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 June 30, 2015 prices, a $6.4 million gain would be reclassified from AOCI over the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.


20


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:
 
June 30, 2015
 
December 31, 2014
 
June 30, 2014
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
17,270,000

 
66
 
19,370,000

 
72
 
16,240,000

 
78
Natural gas options purchased
3,980,000

 
9
 
4,020,000

 
8
 
3,980,000

 
9
Natural gas basis swaps purchased
14,445,000

 
54
 
12,005,000

 
60
 
13,415,000

 
66
__________
(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):
 
June 30, 2015
December 31, 2014
June 30, 2014
Derivative assets, current
$
—

$
—

$
1,737

Derivative assets, non-current
$
—

$
—

$
—

Derivative liabilities, non-current
$
—

$
—

$
—

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
17,907

$
18,740

$
3,561



21


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:
 
June 30, 2015
 
December 31, 2014
 
June 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
1.50

 
2.00

 
2.50

Derivative liabilities, current
$
3,289

 
$
3,340

 
$
3,480

Derivative liabilities, non-current
$
1,433

 
$
2,680

 
$
4,251

__________
(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 June 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 June 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
 
$
(892
)
 
Interest expense
 
$
(1,670
)
 
 
 
$
—

Commodity derivatives
 
(2,245
)
 
Revenue
 
3,666

 
 
 
—

Total
 
$
(3,137
)
 
 
 
$
1,996

 
 
 
$
—


Three Months Ended June 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
 
$
(337
)
 
Interest expense
 
$
(926
)
 
 
 
$
—

Commodity derivatives
 
(2,737
)
 
Revenue
 
(1,251
)
 
 
 
—

Total
 
$
(3,074
)
 
 
 
$
(2,177
)
 
 
 
$
—



22


 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 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
 
$
(1,778
)
 
Interest expense
 
$
(3,107
)
 
 
 
$
—

Commodity derivatives
 
1,520

 
Revenue
 
7,598

 
 
 
—

Total
 
$
(258
)
 
 
 
$
4,491

 
 
 
$
—


 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 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
 
$
(429
)
 
Interest expense
 
$
(1,820
)
 
 
 
$
—

Commodity derivatives
 
(6,209
)
 
Revenue
 
(1,562
)
 
 
 
—

Total
 
$
(6,638
)
 
 
 
$
(3,382
)
 
 
 
$
—



(10)    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.


23


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 as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. A discussion of fair value of financial instruments is included in Note 11:

 
As of June 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
—

5,178

—

 
(5,178
)
—

    Options -- Gas
—

—

—

 
—

—

    Basis Swaps -- Gas
—

4,372

—

 
(4,372
)
—

Commodity derivatives — Utilities
—

2,577

—

 
(2,577
)
—

Total
$
—

$
12,127

$
—

 
$
(12,127
)
$
—

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

Basis Swaps -- Oil
—

112

—

 
(112
)
—

Options -- Gas
—

—

—

 
—

—

Basis Swaps -- Gas
—

498

—

 
(498
)
—

Commodity derivatives — Utilities
—

18,758

—

 
(18,758
)
—

Interest rate swaps
—

4,722

—

 
—

4,722

Total
$
—

$
24,090

$
—

 
$
(19,368
)
$
4,722




24



 
As of December 31, 2014
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total