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EXCEL - IDEA: XBRL DOCUMENT - MDU RESOURCES GROUP INCFinancial_Report.xls
EX-3 - BYLAWS OF MDU RESOURCES GROUP, INC. EX 3 - MDU RESOURCES GROUP INCmdu-3312015q1ex3.htm
EX-10.B - MDU RESOURCES 401 K RETIREMENT PLAN EX 10.B - MDU RESOURCES GROUP INCmdu-331215q1ex10b.htm
EX-32 - CERTIFICATION CEO AND CFO EX 32 - MDU RESOURCES GROUP INCmdu-3312015q1ex32.htm
EX-10.C - MDU RESOURCES SECTION 16 OFFICERS AND DIRECTORS EX10.C - MDU RESOURCES GROUP INCmdu-3312015q1ex10c.htm
EX-31.A - CERTIFICATION OF CHIEF EXECUTIVE OFFICE EX 31.A - MDU RESOURCES GROUP INCmdu-3312015q3ex31a.htm
EX-95 - MINE SAFETY DISCLOSURES EX 95 - MDU RESOURCES GROUP INCmdu-3312015q1ex951.htm
EX-31.B - CERTIFICATION OF CHIEF FINANCIAL OFFICER EX 31.B - MDU RESOURCES GROUP INCmdu-3312015q1ex31b.htm
EX-10.A - MDU RESOURCES 401 K RETIREMENT PLAN EX 10.A - MDU RESOURCES GROUP INCmdu-3312015q1ex10a.htm
EX-12 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES EX 12 - MDU RESOURCES GROUP INCmdu-3312015q1ex121.htm


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

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

For The Quarterly Period Ended March 31, 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 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)

Delaware
 
41-0423660
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)

1200 West Century Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)

(701) 530-1000
(Registrant's telephone number, including area code)

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 ý No o.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 ý 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. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act (Check one):
 
Large accelerated filer ý
Accelerated filer o
 
Non-accelerated filer o
Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý.

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of May 1, 2015: 194,770,955 shares.





DEFINITIONS

The following abbreviations and acronyms used in this Form 10-Q are defined below:

Abbreviation or Acronym
 
2014 Annual Report
Company's Annual Report on Form 10-K for the year ended December 31, 2014
AFUDC
Allowance for funds used during construction
ASC
FASB Accounting Standards Codification
Bbl
Barrel
Bicent
Bicent Power LLC
Big Stone Station
475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
BLM
Bureau of Land Management
BOE
One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas
Bombard Mechanical
Bombard Mechanical, LLC, an indirect wholly owned subsidiary of MDU Construction Services
BOPD
Barrels of oil per day
Brazilian Transmission Lines
Company's former investment in companies owning three electric transmission lines
Btu
British thermal unit
California Superior Court
Superior Court of the State of California, County of Los Angeles (South District - Long Beach)
Calumet
Calumet Specialty Products Partners, L.P.
Cascade
Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CEM
Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
Centennial
Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital
Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial Resources
Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
Clean Water Act
Federal Clean Water Act
Colorado State District Court
Colorado Thirteenth Judicial District Court, Yuma County
Company
MDU Resources Group, Inc.
Connolly-Pacific
Connolly-Pacific Co., an indirect wholly owned subsidiary of Knife River
Coyote Creek
Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station
427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
Dakota Prairie Refinery
20,000-barrel-per-day diesel topping plant built by Dakota Prairie Refining in southwestern North Dakota
Dakota Prairie Refining
Dakota Prairie Refining, LLC, a limited liability company jointly owned by WBI Energy and Calumet
dk
Decatherm
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act
EBITDA
Earnings before interest, taxes, depreciation, depletion and amortization
EPA
U.S. Environmental Protection Agency
ERISA
Employee Retirement Income Security Act of 1974
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
Fidelity
Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
FIP
Funding improvement plan
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Great Plains
Great Plains Natural Gas Co., a public utility division of the Company
Intermountain
Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
JTL
JTL Group, Inc., an indirect wholly owned subsidiary of Knife River
Knife River
Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest
Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
kWh
Kilowatt-hour

2



LWG
Lower Willamette Group
MATS
Mercury and Air Toxics Standards
MBbls
Thousands of barrels
MBOE
Thousands of BOE
Mcf
Thousand cubic feet
MDU Construction Services
MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital
MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MEPP
Multiemployer pension plan
MISO
Midcontinent Independent System Operator, Inc.
MMBtu
Million Btu
MMcf
Million cubic feet
MMdk
Million decatherms
Montana-Dakota
Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ
Montana Department of Environmental Quality
Montana First Judicial District Court
Montana First Judicial District Court, Lewis and Clark County
Montana Seventeenth Judicial District Court
Montana Seventeenth Judicial District Court, Phillips County
MPPAA
Multiemployer Pension Plan Amendments Act of 1980
MTPSC
Montana Public Service Commission
MW
Megawatt
NDPSC
North Dakota Public Service Commission
Nevada State District Court
District Court Clark County, Nevada
NGL
Natural gas liquids
NSPS
New Source Performance Standards
NYMEX
New York Mercantile Exchange
Oil
Includes crude oil and condensate
Omimex
Omimex Canada, Ltd.
OPUC
Oregon Public Utility Commission
Oregon DEQ
Oregon State Department of Environmental Quality
Prairielands
Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
PRP
Potentially Responsible Party
ROD
Record of Decision
RP
Rehabilitation plan
SEC
U.S. Securities and Exchange Commission
SEC Defined Prices
The average price of oil and natural gas during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
Securities Act
Securities Act of 1933, as amended
SourceGas
SourceGas Distribution LLC
VIE
Variable interest entity
WBI Energy
WBI Energy, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Midstream
WBI Energy Midstream, LLC, an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Transmission
WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Holdings
WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC
Washington Utilities and Transportation Commission
WYPSC
Wyoming Public Service Commission


3



INTRODUCTION

The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Cascade distributes natural gas in Oregon and Washington. Intermountain distributes natural gas in Idaho. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added services.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings (comprised of the pipeline and energy services and the exploration and production segments), Knife River (construction materials and contracting segment), MDU Construction Services (construction services segment), Centennial Resources and Centennial Capital (both reflected in the Other category). For more information on the Company's business segments, see Note 15.


4



INDEX

Part I -- Financial Information
Page
 
 
Consolidated Statements of Income --
Three Months Ended March 31, 2015 and 2014
 
 
Consolidated Statements of Comprehensive Income --
Three Months Ended March 31, 2015 and 2014
 
 
Consolidated Balance Sheets --
March 31, 2015 and 2014, and December 31, 2014
 
 
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2015 and 2014
 
 
Notes to Consolidated Financial Statements
 
 
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
Quantitative and Qualitative Disclosures About Market Risk
 
 
Controls and Procedures
 
 
Part II -- Other Information
 
 
 
Legal Proceedings
 
 
Risk Factors
 
 
Mine Safety Disclosures
 
 
Exhibits
 
 
Signatures
 
 
Exhibit Index
 
 
Exhibits
 

5



PART I -- FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
Three Months Ended
 
March 31,
 
2015
2014
 
(In thousands, except per share amounts)
Operating revenues:
 
 
Electric, natural gas distribution and pipeline and energy services
$
427,444

$
491,541

Exploration and production, construction materials and contracting, construction services and other
491,066

551,312

Total operating revenues 
918,510

1,042,853

Operating expenses:
 

 

Fuel and purchased power
23,819

26,544

Purchased natural gas sold
202,960

244,892

Cost of crude oil
2,270


Operation and maintenance:
 

 

Electric, natural gas distribution and pipeline and energy services
79,425

67,284

Exploration and production, construction materials and contracting, construction services and other
440,993

445,951

Depreciation, depletion and amortization
95,507

99,557

Taxes, other than income
47,483

55,721

Write-down of oil and natural gas properties (Note 5)
500,400


Total operating expenses
1,392,857

939,949

Operating income (loss)
(474,347
)
102,904

Other income
2,324

2,183

Interest expense
23,149

20,971

Income (loss) before income taxes
(495,172
)
84,116

Income taxes
(185,727
)
27,932

Income (loss) from continuing operations
(309,445
)
56,184

Loss from discontinued operations, net of tax (Note 10)

(45
)
Net income (loss)
(309,445
)
56,139

Net loss attributable to noncontrolling interest
(3,528
)
(523
)
Dividends declared on preferred stocks
171

171

Earnings (loss) on common stock
$
(306,088
)
$
56,491

 
 
 
Earnings (loss) per common share - basic:
 

 

Earnings (loss) before discontinued operations
$
(1.57
)
$
.30

Discontinued operations, net of tax


Earnings (loss) per common share - basic
$
(1.57
)
$
.30

 
 
 
Earnings (loss) per common share - diluted:
 

 

Earnings (loss) before discontinued operations
$
(1.57
)
$
.30

Discontinued operations, net of tax


Earnings (loss) per common share - diluted
$
(1.57
)
$
.30

 
 
 
Dividends declared per common share
$
.1825

$
.1775

 
 
 
Weighted average common shares outstanding - basic
194,479

189,820

 
 
 
Weighted average common shares outstanding - diluted
194,479

190,432

The accompanying notes are an integral part of these consolidated financial statements.

6



MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

 
Three Months Ended
 
March 31,
 
2015
2014
 
(In thousands)
Net income (loss)
$
(309,445
)
$
56,139

Other comprehensive income:
 
 
Reclassification adjustment for loss on derivative instruments included in net income (loss), net of tax of $60 and $204 for the three months ended in 2015 and 2014, respectively
99

344

Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $230 and $168 for the three months ended in 2015 and 2014, respectively
375

275

Foreign currency translation adjustment:
 
 
Foreign currency translation adjustment recognized during the period, net of tax of $(68) and $28 for the three months ended in 2015 and 2014, respectively
(112
)
46

Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss), net of tax of $490 and $0 for the three months ended in 2015 and 2014, respectively
802


Foreign currency translation adjustment
690

46

Net unrealized gain on available-for-sale investments:
 
 
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(11) and $(19) for the three months ended in 2015 and 2014, respectively
(21
)
(36
)
Reclassification adjustment for loss on available-for-sale investments included in net income (loss), net of tax of $19 and $20 for the three months ended in 2015 and 2014, respectively
36

38

Net unrealized gain on available-for-sale investments
15

2

Other comprehensive income
1,179

667

Comprehensive income (loss)
(308,266
)
56,806

Comprehensive loss attributable to noncontrolling interest
(3,528
)
(523
)
Comprehensive income (loss) attributable to common stockholders
$
(304,738
)
$
57,329

The accompanying notes are an integral part of these consolidated financial statements.



7



MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

 
March 31, 2015
March 31, 2014
December 31, 2014
(In thousands, except shares and per share amounts)
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
122,241

$
83,700

$
81,855

Receivables, net
564,090

690,761

693,318

Inventories
336,598

301,332

300,811

Deferred income taxes
32,987

29,427

23,806

Commodity derivative instruments
7,127

81

18,335

Prepayments and other current assets
98,503

99,229

76,848

Total current assets
1,161,546

1,204,530

1,194,973

Investments
118,407

113,763

117,920

Property, plant and equipment
9,299,713

9,150,269

9,693,171

Less accumulated depreciation, depletion and amortization
4,233,193

3,954,442

4,166,407

Net property, plant and equipment
5,066,520

5,195,827

5,526,764

Deferred charges and other assets:
 

 

 

Goodwill
635,204

636,039

635,204

Other intangible assets, net
9,166

12,296

9,840

Other
326,542

246,394

325,277

Total deferred charges and other assets 
970,912

894,729

970,321

Total assets
$
7,317,385

$
7,408,849

$
7,809,978

LIABILITIES AND EQUITY
 

 

 

Current liabilities:
 

 

 

Short-term borrowings
$
16,100

$

$

Long-term debt due within one year
409,292

12,227

269,449

Accounts payable
259,881

399,935

382,671

Taxes payable
48,436

61,847

45,631

Dividends payable
35,687

33,980

35,607

Accrued compensation
37,797

40,016

62,775

Commodity derivative instruments

12,186


Other accrued liabilities
179,672

185,287

172,561

Total current liabilities 
986,865

745,478

968,694

Long-term debt
1,780,694

2,093,605

1,825,278

Deferred credits and other liabilities:
 

 

 

Deferred income taxes
804,757

899,420

952,413

Other liabilities
810,626

720,542

813,809

Total deferred credits and other liabilities 
1,615,383

1,619,962

1,766,222

Commitments and contingencies
 

 

 

Equity:
 

 

 

Preferred stocks
15,000

15,000

15,000

Common stockholders' equity:
 

 

 

Common stock
 

 

 

Authorized - 500,000,000 shares, $1.00 par value
 
 
 
Shares issued - 195,191,129 at March 31, 2015,
191,838,720 at March 31, 2014 and 194,754,812 at December 31, 2014
195,191

191,839

194,755

Other paid-in capital
1,214,867

1,110,221

1,207,188

Retained earnings
1,421,220

1,625,692

1,762,827

Accumulated other comprehensive loss
(40,924
)
(37,538
)
(42,103
)
Treasury stock at cost - 538,921 shares
(3,626
)
(3,626
)
(3,626
)
Total common stockholders' equity
2,786,728

2,886,588

3,119,041

Total stockholders' equity
2,801,728

2,901,588

3,134,041

Noncontrolling interest
132,715

48,216

115,743

Total equity
2,934,443

2,949,804

3,249,784

Total liabilities and equity 
$
7,317,385

$
7,408,849

$
7,809,978

The accompanying notes are an integral part of these consolidated financial statements.

8



MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
Three Months Ended
 
March 31,
 
2015
2014
 
(In thousands)
Operating activities:
 
 
Net income (loss)
$
(309,445
)
$
56,139

Loss from discontinued operations, net of tax

(45
)
Income (loss) from continuing operations
(309,445
)
56,184

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 

Depreciation, depletion and amortization
95,507

99,557

Deferred income taxes
(160,633
)
35,965

Unrealized loss on commodity derivatives
11,208

6,712

Write-down of oil and natural gas properties
500,400


Changes in current assets and liabilities, net of acquisitions:
 

 
Receivables
101,371

25,611

Inventories
(44,408
)
(19,809
)
Other current assets
(20,349
)
(22,324
)
Accounts payable
(53,334
)
(11,525
)
Other current liabilities
(16,119
)
(28,355
)
Other noncurrent changes
(9,537
)
(4,987
)
Net cash provided by continuing operations
94,661

137,029

Net cash provided by discontinued operations

8

Net cash provided by operating activities
94,661

137,037

 
 
 
Investing activities:
 

 

Capital expenditures
(189,463
)
(179,646
)
Acquisitions, net of cash acquired

(206,304
)
Net proceeds from sale or disposition of property and other
26,801

5,179

Investments
2,449

458

Net cash used in continuing operations
(160,213
)
(380,313
)
Net cash provided by discontinued operations


Net cash used in investing activities
(160,213
)
(380,313
)
 
 
 
Financing activities:
 

 

Issuance of short-term borrowings
16,100


Repayment of short-term borrowings

(11,500
)
Issuance of long-term debt
149,332

309,501

Repayment of long-term debt
(54,162
)
(58,232
)
Proceeds from issuance of common stock
9,864

54,843

Dividends paid
(35,607
)
(33,737
)
Excess tax benefit on stock-based compensation

4,833

Contribution from noncontrolling interest
20,500

16,000

Net cash provided by continuing operations
106,027

281,708

Net cash provided by discontinued operations


Net cash provided by financing activities
106,027

281,708

Effect of exchange rate changes on cash and cash equivalents
(89
)
43

Increase in cash and cash equivalents
40,386

38,475

Cash and cash equivalents -- beginning of year
81,855

45,225

Cash and cash equivalents -- end of period
$
122,241

$
83,700

The accompanying notes are an integral part of these consolidated financial statements.

9



MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS

March 31, 2015 and 2014
(Unaudited)

Note 1 - Basis of presentation
The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's 2014 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2014 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after March 31, 2015, up to the date of issuance of these consolidated interim financial statements.

Note 2 - Seasonality of operations
Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.

Note 3 - Accounts receivable and allowance for doubtful accounts
Accounts receivable consist primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $29.3 million, $22.6 million and $30.9 million at March 31, 2015 and 2014, and December 31, 2014, respectively.

The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts at March 31, 2015 and 2014, and December 31, 2014, was $9.4 million, $10.9 million and $9.5 million, respectively.

Note 4 - Inventories and natural gas in storage
Inventories, other than natural gas in storage for the Company's regulated operations, are stated at the lower of average cost or market value. Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year is included in inventories. Inventories consisted of:
 
March 31, 2015
March 31, 2014
December 31, 2014
 
(In thousands)
Aggregates held for resale
$
112,029

$
104,106

$
108,161

Asphalt oil
89,578

66,292

42,135

Materials and supplies
65,599

68,809

65,683

Merchandise for resale
15,688

22,463

24,420

Natural gas in storage (current)
9,303

6,129

19,302

Other
44,401

33,533

41,110

Total
$
336,598

$
301,332

$
300,811


The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, is included in other assets and was $49.3 million, $47.4 million and $49.3 million at March 31, 2015 and 2014, and December 31, 2014, respectively.

Note 5 - Oil and natural gas properties
The company uses the full-cost method of accounting for its oil and natural gas production activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and amortized on

10



the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized.

Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties not subject to amortization, plus the effects of cash flow hedges, less applicable income taxes. Proved reserves and associated future cash flows are determined based on SEC Defined Prices and exclude cash outflows associated with asset retirement obligations that have been accrued on the balance sheet. If capitalized costs, less accumulated amortization and related deferred income taxes, exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.

The Company's capitalized cost under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2015. SEC Defined Prices, adjusted for market differentials, are used to calculate the ceiling test. Accordingly, the Company was required to write down its oil and natural gas producing properties. The noncash write-down amounted to $500.4 million ($315.3 million after tax) for the three months ended March 31, 2015.

At March 31, 2014 and December 31, 2014, the Company's full-cost ceiling exceeded the Company's capitalized cost. Various factors, including lower SEC Defined Prices, market differentials, changes in estimates of proved reserve quantities, unsuccessful results of exploration and development efforts or changes in operating and development costs could result in future noncash write-downs of the Company's oil and natural gas properties.

SEC Defined Prices for each quarter for the last 12 months were as follows:
SEC Defined Prices for the 12 months ended
NYMEX
Oil Price
(per Bbl)

Henry Hub
Gas Price
(per MMBtu)

Ventura
Gas Price
(per MMBtu)

March 31, 2015
$
82.72

$
3.87

$
3.96

December 31, 2014
94.99

4.34

7.71

September 30, 2014
99.08

4.24

7.60

June 30, 2014
100.27

4.10

7.47


For purposes of comparison, first-of-the-month prices were as follows:
 
NYMEX
Oil Price
(per Bbl)

Henry Hub
Gas Price
(per MMBtu)

Ventura
Gas Price
(per MMBtu)

April 2015
$
50.09

$
2.63

$
2.45

May 2015
59.15

2.57

2.51


Given the current oil and natural gas pricing environment, the Company believes it is likely it will have noncash write-downs of its oil and natural gas properties in future quarters until such time as commodity prices begin to recover.

Note 6 - Earnings (loss) per common share
Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the applicable period, plus the effect of outstanding performance share awards. Diluted loss per common share for the period ended March 31, 2015, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the period. Due to the loss on common stock for the period ended March 31, 2015, the effect of outstanding performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. In 2014, there were no shares excluded from the calculation of diluted earnings per share. Common stock outstanding includes issued shares less shares held in treasury. Net income (loss) was the same for both the basic and diluted earnings (loss) per share calculations. A reconciliation of the weighted average common shares outstanding used in the basic and diluted earnings (loss) per share calculations was as follows:

11



 
Three Months Ended
 
March 31,
 
2015

2014

 
(In thousands)
Weighted average common shares outstanding - basic
194,479

189,820

Effect of dilutive performance share awards

612

Weighted average common shares outstanding - diluted
194,479

190,432

Shares excluded from the calculation of diluted earnings per share
87



Note 7 - Cash flow information
Cash expenditures for interest and income taxes were as follows:
 
Three Months Ended
 
March 31,
 
2015

2014

 
(In thousands)
Interest, net of amounts capitalized and AFUDC - borrowed of $2.6 million and $2.4 million in 2015 and 2014, respectively
$
23,874

$
20,850

Income taxes paid (refunded), net
$
(1,339
)
$
9,435


Noncash investing transactions were as follows:
 
March 31,
 
2015

2014

 
(In thousands)
Property, plant and equipment additions in accounts payable
$
54,134

$
65,736


Note 8 - New Accounting Standards
Revenue from Contracts with Customers In May 2014, the FASB issued guidance on accounting for revenue from contracts with customers. The guidance provides for a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry specific guidance. This guidance will be effective for the Company on January 1, 2017. In April 2015, the FASB tentatively decided to defer the effective date one year and allow entities to early adopt. If these proposals are adopted, the guidance would be effective for the Company on January 1, 2018. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting the guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. In addition, the modified approach will require additional disclosures. The Company is evaluating the effects the adoption of the new revenue guidance will have on its results of operations, financial position, cash flows and disclosures, as well as its method of adoption.

Simplifying the Presentation of Debt Issuance Costs In April 2015, the FASB issued guidance on simplifying the presentation of debt issuance costs in the financial statements. This guidance requires entities to present debt issuance costs as a direct deduction to the related debt liability. The amortization of these costs will be reported as interest expense. The guidance will be effective for the Company on January 1, 2016, and is to be applied retrospectively. Early adoption of this guidance is permitted. The guidance will require a reclassification of the debt issuance costs on the Consolidated Balance Sheets, but will not impact the Company's results of operations or cash flows.


12



Note 9 - Comprehensive income (loss)
The after-tax changes in the components of accumulated other comprehensive loss were as follows:
Three Months Ended March 31, 2015
Net Unrealized Gain (Loss) on Derivative
 Instruments
 Qualifying as Hedges
Postretirement
 Liability Adjustment
Foreign Currency Translation Adjustment
Net Unrealized Gain (Loss) on Available-for-sale Investments
Total Accumulated
 Other
Comprehensive
 Loss
 
(In thousands)
Balance at beginning of period
$
(3,071
)
$
(38,218
)
$
(829
)
$
15

$
(42,103
)
Other comprehensive loss before reclassifications


(112
)
(21
)
(133
)
Amounts reclassified from accumulated other comprehensive loss
99

375

802

36

1,312

Net current-period other comprehensive income
99

375

690

15

1,179

Balance at end of period
$
(2,972
)
$
(37,843
)
$
(139
)
$
30

$
(40,924
)

Three Months Ended March 31, 2014
Net Unrealized Gain (Loss) on Derivative
 Instruments
 Qualifying as Hedges
Postretirement
 Liability Adjustment
Foreign Currency Translation Adjustment
Net Unrealized Gain (Loss) on Available-for-sale Investments
Total Accumulated
 Other
Comprehensive
 Loss
 
(In thousands)
Balance at beginning of period
$
(3,765
)
$
(33,807
)
$
(667
)
$
34

$
(38,205
)
Other comprehensive income (loss) before reclassifications


46

(36
)
10

Amounts reclassified from accumulated other comprehensive loss
344

275


38

657

Net current-period other comprehensive income
344

275

46

2

667

Balance at end of period
$
(3,421
)
$
(33,532
)
$
(621
)
$
36

$
(37,538
)
 
 
 
 
 
 
 
 
 
 
 
 


13



Reclassifications out of accumulated other comprehensive loss were as follows:
 
Three Months Ended
Location on Consolidated Statements of Income
 
March 31, 2015
March 31, 2014
 
 
(In thousands)
 
Reclassification adjustment for loss on derivative instruments included in net income (loss):
 
 
 
Commodity derivative instruments
$

$
(388
)
Operating revenues
Interest rate derivative instruments
(159
)
(160
)
Interest expense
 
(159
)
(548
)
 
 
60

204

Income taxes
 
(99
)
(344
)
 
Amortization of postretirement liability losses included in net periodic benefit cost
(605
)
(443
)
(a)
 
230

168

Income taxes
 
(375
)
(275
)
 
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss)
(1,292
)

Other income
 
490


Income taxes
 
(802
)

 
Reclassification adjustment for loss on available-for-sale investments included in net income (loss)
(55
)
(58
)
Other income
 
19

20

Income taxes
 
(36
)
(38
)
 
Total reclassifications
$
(1,312
)
$
(657
)
 
 (a) Included in net periodic benefit cost (credit). For more information, see Note 16.
 

Note 10 - Discontinued operations
In 2007, Centennial Resources sold CEM to Bicent. In connection with the sale, Centennial Resources agreed to indemnify Bicent and its affiliates from certain third party claims arising out of or in connection with Centennial Resources' ownership or operation of CEM prior to the sale. In addition, Centennial had previously guaranteed CEM's obligations under a construction contract. The Company incurred legal expenses in the first quarter of 2014, which are reflected in discontinued operations in the consolidated financial statements and accompanying notes at March 31, 2014. Discontinued operations are included in the Other category.

Note 11 - Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Three Months Ended
March 31, 2015
Balance
as of
January 1,
2015*
Goodwill
Acquired
During
the Year
Balance
as of
March 31, 2015*
 
(In thousands)
Natural gas distribution
$
345,736

$

$
345,736

Pipeline and energy services
9,737


9,737

Construction materials and contracting
176,290


176,290

Construction services
103,441


103,441

Total
$
635,204

$

$
635,204

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
 


14



Three Months Ended
March 31, 2014
Balance
as of
January 1,
2014*
Goodwill
Acquired
During the
Year
Balance
as of
March 31, 2014*
 
(In thousands)
Natural gas distribution
$
345,736

$

$
345,736

Pipeline and energy services
9,737


9,737

Construction materials and contracting
176,290


176,290

Construction services
104,276


104,276

Total
$
636,039

$

$
636,039

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.


Year Ended
December 31, 2014
Balance
as of
January 1,
2014*
Goodwill
Acquired
During the
Year/Other
Balance
as of
December 31,
2014*
 
(In thousands)
Natural gas distribution
$
345,736

$

$
345,736

Pipeline and energy services
9,737


9,737

Construction materials and contracting
176,290


176,290

Construction services
104,276

(835
)
103,441

Total
$
636,039

$
(835
)
$
635,204

  * Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
 

Other amortizable intangible assets were as follows:
 
March 31, 2015
March 31, 2014
December 31, 2014
 
(In thousands)
Customer relationships
$
20,975

$
21,310

$
21,310

Accumulated amortization
(15,649
)
(14,230
)
(15,556
)
 
5,326

7,080

5,754

Noncompete agreements
4,409

5,580

5,080

Accumulated amortization
(3,504
)
(4,335
)
(4,098
)
 
905

1,245

982

Other
8,300

10,920

10,921

Accumulated amortization
(5,365
)
(6,949
)
(7,817
)
 
2,935

3,971

3,104

Total
$
9,166

$
12,296

$
9,840


Amortization expense for amortizable intangible assets for the three months ended March 31, 2015 and 2014, was $700,000 and $800,000, respectively. Estimated amortization expense for amortizable intangible assets is $2.5 million in 2015, $2.2 million in 2016, $1.9 million in 2017, $1.0 million in 2018, $900,000 in 2019 and $1.4 million thereafter.

Note 12 - Derivative instruments
The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. As of March 31, 2015, the Company had no outstanding foreign currency or interest rate hedges.

The fair value of derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability.


15



Fidelity
At March 31, 2015 and 2014, and December 31, 2014, Fidelity held oil swap and collar agreements with total forward notional volumes of 958,000, 2.7 million and 270,000 Bbl, respectively, and natural gas swap agreements with total forward notional volumes of 2.8 million, 14.7 million and 5.0 million MMBtu, respectively. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of oil and natural gas on its forecasted sales of oil and natural gas production.

Effective April 1, 2013, Fidelity elected to de-designate all commodity derivative contracts previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively for all of its commodity derivative instruments. When the criteria for hedge accounting is not met or when hedge accounting is not elected, realized gains and losses and unrealized gains and losses are both recorded in operating revenues on the Consolidated Statements of Income. As a result of discontinuing hedge accounting on commodity derivative instruments, gains and losses on the oil and natural gas derivative instruments remain in accumulated other comprehensive income (loss) as of the de-designation date and are reclassified into earnings in future periods as the underlying hedged transactions affect earnings. At April 1, 2013, accumulated other comprehensive income (loss) included $1.8 million of unrealized gains, representing the mark-to-market value of the Company's commodity derivative instruments that qualified as cash flow hedges as of the balance sheet date, which the Company has subsequently reclassified into earnings.

Prior to April 1, 2013, changes in the fair value attributable to the effective portion of the hedging instruments, net of tax, were recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). To the extent that the hedges were not effective or did not qualify for hedge accounting, the ineffective portion of the changes in fair market value was recorded directly in earnings. Gains and losses on the oil and natural gas derivative instruments were reclassified from accumulated other comprehensive income (loss) into operating revenues on the Consolidated Statements of Income at the date the oil and natural gas quantities were settled.

Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity or any of its affiliates fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of the derivative instruments in liability positions. Fidelity had no derivative instruments that were in a liability position with credit-risk-related contingent features at March 31, 2015 and December 31, 2014. The aggregate fair value of Fidelity's derivative instruments with credit-risk related contingent features that were in a liability position at March 31, 2014, were $12.2 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on March 31, 2014, were $12.2 million.

Centennial
Centennial has historically entered into interest rate derivative instruments to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt. As of March 31, 2015 and 2014, and December 31, 2014, Centennial had no outstanding interest rate swap agreements.

Fidelity and Centennial
The gains and losses on derivative instruments were as follows:
 
Three Months Ended
 
March 31,
 
2015
2014
 
(In thousands)
Commodity derivatives designated as cash flow hedges:
 
 
Amount of loss reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax
$

$
244

 
 
 
Interest rate derivatives designated as cash flow hedges:
 
 
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax
99

100

 
 
 
Commodity derivatives not designated as hedging instruments:
 
 
Amount of loss recognized in operating revenues, before tax
(11,208
)
(6,712
)

Over the next 12 months net losses of approximately $400,000 (after tax) are estimated to be reclassified from accumulated other comprehensive income (loss) into earnings, as the hedged transactions affect earnings.


16



The location and fair value of the gross amount of the Company's derivative instruments on the Consolidated Balance Sheets were as follows:
Asset
Derivatives
Location on
Consolidated
Balance Sheets
Fair Value at March 31, 2015
Fair Value at March 31, 2014
Fair Value at December 31, 2014
 
 
(In thousands)
Not designated as hedges:
 

 
 
Commodity derivatives
Commodity derivative instruments
$
7,127

$
81

$
18,335

 
Other assets - noncurrent

249


Total asset derivatives
 
$
7,127

$
330

$
18,335


Liability
Derivatives
Location on
Consolidated
Balance Sheets
Fair Value at March 31, 2015
Fair Value at March 31, 2014
Fair Value at December 31, 2014
 
 
(In thousands)
Not designated as hedges:
 

 

 

Commodity derivatives
Commodity derivative instruments
$

$
12,186

$

Total liability derivatives
 
$

$
12,186

$


All of the Company's commodity derivative instruments at March 31, 2015 and 2014, and December 31, 2014, were subject to legally enforceable master netting agreements. However, the Company's policy is to not offset fair value amounts for derivative instruments and, as a result, the Company's derivative assets and liabilities are presented gross on the Consolidated Balance Sheets. The gross derivative assets and liabilities (excluding settlement receivables and payables that may be subject to the same master netting agreements) presented on the Consolidated Balance Sheets and the amount eligible for offset under the master netting agreements is presented in the following table:
March 31, 2015
Gross Amounts Recognized on the Consolidated Balance Sheets
Gross Amounts Not Offset on the Consolidated Balance Sheets
Net
 
(In thousands)
Assets:
 
 
 
Commodity derivatives
$
7,127

$

$
7,127

Total assets
$
7,127

$

$
7,127


March 31, 2014
Gross Amounts Recognized on the Consolidated Balance Sheets
Gross Amounts Not Offset on the Consolidated Balance Sheets
Net
 
(In thousands)
Assets:
 
 
 
Commodity derivatives
$
330

$
(330
)
$

Total assets
$
330

$
(330
)
$

Liabilities:
 
 
 
Commodity derivatives
$
12,186

$
(330
)
$
11,856

Total liabilities
$
12,186

$
(330
)
$
11,856


December 31, 2014
Gross Amounts Recognized on the Consolidated Balance Sheets
Gross Amounts Not Offset on the Consolidated Balance Sheets
Net
 
(In thousands)
Assets:
 
 
 
Commodity derivatives
$
18,335

$

$
18,335

Total assets
$
18,335

$

$
18,335



17



Note 13 - Fair value measurements
The Company measures its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments, which consist of an insurance contract, to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $67.8 million, $63.3 million and $65.8 million, at March 31, 2015 and 2014, and December 31, 2014, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments were $2.0 million and $900,000 for the three months ended March 31, 2015 and 2014, respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income.

The Company did not elect the fair value option, which records gains and losses in income, for its available-for-sale securities, which include mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as Investments on the Consolidated Balance Sheets. Unrealized gains or losses are recorded in accumulated other comprehensive income (loss). Details of available-for-sale securities were as follows:
March 31, 2015
Cost
Gross Unrealized Gains
Gross Unrealized Losses
Fair Value
 
(In thousands)
Mortgage-backed securities
$
7,792

$
58

$
(18
)
$
7,832

U.S. Treasury securities
2,337

9

(4
)
2,342

Total
$
10,129

$
67

$
(22
)
$
10,174


March 31, 2014
Cost
Gross Unrealized Gains
Gross Unrealized Losses
Fair Value
 
(In thousands)
Mortgage-backed securities
$
7,943

$
63

$
(17
)
$
7,989

U.S. Treasury securities
2,069

9


2,078

Total
$
10,012

$
72

$
(17
)
$
10,067


December 31, 2014
Cost
Gross Unrealized Gains
Gross Unrealized Losses
Fair Value
 
(In thousands)
Mortgage-backed securities
$
6,594

$
60

$
(18
)
$
6,636

U.S. Treasury securities
3,574


(19
)
3,555

Total
$
10,168

$
60

$
(37
)
$
10,191


The fair value of the Company's money market funds approximates cost.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs.

The estimated fair values of the Company's assets and liabilities measured on a recurring basis are determined using the market approach.

The Company's Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company's Level 2 mortgage-backed securities and U.S. Treasury securities are based on comparable market transactions, other observable inputs or other sources, including pricing from outside sources.

The estimated fair value of the Company's Level 2 insurance contract is based on contractual cash surrender values that are determined primarily by investments in managed separate accounts of the insurer. These amounts approximate fair value. The managed separate accounts are valued based on other observable inputs or corroborated market data.


18



The estimated fair value of the Company's Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company's and the counterparties' nonperformance risk is also evaluated.

Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. For the three months ended March 31, 2015 and 2014, there were no transfers between Levels 1 and 2.

The Company's assets and liabilities measured at fair value on a recurring basis were as follows:
 
Fair Value Measurements at March 31, 2015, Using
 
 
Quoted Prices in
Active Markets
for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Balance at March 31, 2015
 
(In thousands)
Assets:
 
 
 
 
Money market funds
$

$
16,945

$

$
16,945

Insurance contract*

67,797


67,797

Available-for-sale securities:
 
 
 
 
Mortgage-backed securities

7,832


7,832

U.S. Treasury securities

2,342


2,342

Commodity derivative instruments

7,127


7,127

Total assets measured at fair value
$

$
102,043

$

$
102,043

* The insurance contract invests approximately 20 percent in common stock of mid-cap companies, 18 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies, 32 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents.
 

 
Fair Value Measurements at March 31, 2014, Using
 
 
Quoted Prices in Active Markets for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Balance at March 31, 2014
 
(In thousands)
Assets:
 
 
 
 
Money market funds
$

$
20,267

$

$
20,267

Insurance contract*

63,269


63,269

Available-for-sale securities:
 
 
 
 
Mortgage-backed securities

7,989


7,989

U.S. Treasury securities

2,078


2,078

Commodity derivative instruments

330


330

Total assets measured at fair value
$

$
93,933

$

$
93,933

Liabilities:
 
 
 
 
Commodity derivative instruments
$

$
12,186

$

$
12,186

Total liabilities measured at fair value
$

$
12,186

$

$
12,186

* The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 27 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 16 percent in fixed-income investments.
 


19



 
Fair Value Measurements at December 31, 2014, Using
 
 
Quoted Prices in Active Markets for Identical Assets
 (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
 (Level 3)
Balance at December 31, 2014
 
(In thousands)
Assets:
 
 
 
 
Money market funds
$

$
18,473

$

$
18,473

Insurance contract*

65,831


65,831

Available-for-sale securities:
 
 
 
 
Mortgage-backed securities

6,636


6,636

U.S. Treasury securities

3,555


3,555

Commodity derivative instruments

18,335


18,335

Total assets measured at fair value
$

$
112,830

$

$
112,830

* The insurance contract invests approximately 20 percent in common stock of mid-cap companies, 18 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies, 32 percent in fixed-income investments and 1 percent in cash equivalents.
 

The Company's long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The fair value was based on discounted future cash flows using current market interest rates. The estimated fair value of the Company's Level 2 long-term debt was as follows:
 
Carrying
Amount
Fair
Value
 
(In thousands)
Long-term debt at March 31, 2015
$
2,189,986

$
2,340,681

Long-term debt at March 31, 2014
$
2,105,832

$
2,186,839

Long-term debt at December 31, 2014
$
2,094,727

$
2,239,445


The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.

Note 14 - Equity
A summary of the changes in equity was as follows:
Three Months Ended March 31, 2015
Total Stockholders' Equity
Noncontrolling Interest
Total Equity
 
(In thousands)
Balance at December 31, 2014
$
3,134,041

$
115,743

$
3,249,784

Net loss
(305,917
)
(3,528
)
(309,445
)
Other comprehensive income
1,179


1,179

Dividends declared on preferred stocks
(171
)

(171
)
Dividends declared on common stock
(35,515
)

(35,515
)
Stock-based compensation
(121
)

(121
)
Net tax deficit on stock-based compensation
(1,632
)

(1,632
)
Issuance of common stock
9,864


9,864

Contribution from noncontrolling interest

20,500

20,500

Balance at March 31, 2015
$
2,801,728

$
132,715

$
2,934,443



20



Three Months Ended March 31, 2014
Total Stockholders' Equity
Noncontrolling Interest
Total Equity
 
(In thousands)
Balance at December 31, 2013
$
2,823,164

$
32,738

$
2,855,902

Net income (loss)
56,662

(523
)
56,139

Other comprehensive income
667


667

Dividends declared on preferred stocks
(171
)

(171
)
Dividends declared on common stock
(33,809
)

(33,809
)
Stock-based compensation
1,336


1,336

Issuance of common stock upon vesting of performance shares, net of shares used for tax withholdings
(5,564
)

(5,564
)
Excess tax benefit on stock-based compensation
4,729


4,729

Issuance of common stock
54,574


54,574

Contribution from noncontrolling interest

16,001

16,001

Balance at March 31, 2014
$
2,901,588

$
48,216

$
2,949,804


Note 15 - Business segment data
The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The internal reporting of these operating segments is defined based on the reporting and review process used by the Company's chief executive officer. The vast majority of the Company's operations are located within the United States.

The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added services.

The pipeline and energy services segment provides natural gas transportation, underground storage, processing and gathering services, as well as oil gathering, through regulated and nonregulated pipeline systems and processing facilities primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment recently commenced operations of Dakota Prairie Refinery in conjunction with Calumet to refine crude oil. The facility has begun producing diesel fuel and is expected to begin sales of diesel during May 2015. This segment also provides cathodic protection and other energy-related services.

The exploration and production segment is engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. The Company intends to market its exploration and production business in the future. The plan to market this business has been delayed due to low oil prices.

The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.

The construction services segment provides utility construction services specializing in constructing and maintaining electric and communications lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization. This segment also provides utility excavation and inside electrical and mechanical services, and manufactures and distributes transmission line construction equipment and supplies.

The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies' general liability, automobile liability and pollution liability coverages. Centennial Capital also owns certain real and personal property. The Other category also included Centennial Resources' investment in the Brazilian Transmission Lines.

The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the 2014 Annual Report. Information on the Company's businesses was as follows:

21



Three Months Ended March 31, 2015
External
Operating
Revenues
Inter-
segment
Operating
Revenues
Earnings (Loss)
on Common
Stock
 
(In thousands)
Electric
$
71,776

$

$
8,328

Natural gas distribution
330,573


21,450

Pipeline and energy services
25,095

21,341

4,018

 
427,444

21,341

33,796

Exploration and production
49,710

5,226

(328,904
)
Construction materials and contracting
205,658

948

(14,635
)
Construction services
235,403

11,695

4,760

Other
295

1,772

(255
)
 
491,066

19,641

(339,034
)
Intersegment eliminations

(40,982
)
(850
)
Total
$
918,510

$

$
(306,088
)

Three Months Ended March 31, 2014
External
Operating
Revenues
Inter-
segment
Operating
Revenues
Earnings (Loss)
on Common
Stock
 
(In thousands)
Electric
$
73,647

$

$
11,033

Natural gas distribution
374,233


27,263

Pipeline and energy services
43,661

18,276

4,349

 
491,541

18,276

42,645

Exploration and production
116,669

20,867

20,939

Construction materials and contracting
164,423

4,017

(23,574
)
Construction services
269,892

3,738

16,568

Other
328

1,724

264

 
551,312

30,346

14,197

Intersegment eliminations

(48,622
)
(351
)
Total
$
1,042,853

$

$
56,491

 
 
 
 
 
 
 
 
Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from exploration and production, construction materials and contracting, construction services and other are all from nonregulated operations.


22



Note 16 - Employee benefit plans
Pension and other postretirement plans
The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans were as follows:
 
 
 
Other
 
 
 
Postretirement
 
Pension Benefits
Benefits
Three Months Ended March 31,
2015

2014

2015

2014

 
(In thousands)
Components of net periodic benefit cost:
 
 
 
 
Service cost
$
40

$
33

$
483

$
379

Interest cost
4,364

4,440

914

858

Expected return on assets
(5,373
)
(5,125
)
(1,175
)
(1,067
)
Amortization of prior service cost (credit)
18

18

(342
)
(348
)
Amortization of net actuarial loss
1,735

1,313

461

318

Net periodic benefit cost, including amount capitalized
784

679

341

140

Less amount capitalized
76

95

29

29

Net periodic benefit cost
$
708

$
584

$
312

$
111

 
 
 
 
 
Nonqualified benefit plans
In addition to the qualified plan defined pension benefits reflected in the table, the Company has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three months ended March 31, 2015 and 2014, was $1.7 million and $1.7 million, respectively.

Multiemployer plans
On September 24, 2014, Knife River provided notice to the Operating Engineers Local 800 & WY Contractors Association, Inc. Pension Plan for Wyoming that it was withdrawing from the plan effective October 26, 2014. The plan administrator will determine Knife River's withdrawal liability. For the three months ended March 31, 2015, the Company accrued an additional withdrawal liability of approximately $2.4 million (approximately $1.5 million after tax). The total withdrawal liability is currently estimated at $16.4 million (approximately $9.8 million after tax). The assessed withdrawal liability for this plan may be significantly different from the current estimate.

Note 17 - Regulatory matters and revenues subject to refund
On August 11, 2014, Montana-Dakota filed an application with the MTPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $3.0 million annually or approximately 3.6 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, depreciation and taxes associated with the increased investment as well as an increase in Montana-Dakota's operation and maintenance expenses. On February 3, 2015, the MTPSC approved an interim increase of $2.0 million or approximately 2.3 percent, subject to refund, to be effective with service rendered on and after February 6, 2015. On March 18, 2015, Montana-Dakota and the Montana Consumer Counsel filed a settlement agreement that resolved all issues of the application and reflected a natural gas rate increase of $2.5 million annually or approximately 3.0 percent. An amended stipulation reflecting minor changes in rate design was submitted on March 24, 2015. On April 28, 2015, the MTPSC approved the settlement rates, which are expected to be effective with service rendered on and after May 11, 2015.

On October 3, 2014, Montana-Dakota filed an application with the WYPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $788,000 annually or approximately 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities and the associated operation and maintenance expenses, depreciation and taxes associated with the increase in investment. On April 16, 2015, Montana-Dakota and the Wyoming Office of Consumer Advocate filed a stipulation and agreement that resolved all issues between the parties and reflected a natural gas rate increase of $501,000 annually or approximately 2.6 percent. The WYPSC has scheduled a hearing for this matter on May 19, 2015.

23




On November 14, 2014, Montana-Dakota filed an application with the NDPSC for approval to implement the rate adjustment associated with the electric generation resource recovery rider approved by the NDPSC on August 20, 2014. On January 7, 2015, the NDPSC approved the rate adjustments of $5.3 million annually to be effective with service rendered on and after January 9, 2015.

On December 22, 2014, Montana-Dakota filed an application for advance determination of prudence and a certificate of public convenience and necessity with the NDPSC for the Thunder Spirit Wind project. This project will provide energy, capacity and renewable energy credits to Montana-Dakota's electric customers in North Dakota, Montana and South Dakota. The NDPSC has scheduled a hearing for this matter on May 14, 2015.

On February 6, 2015, Montana-Dakota filed an application with the NDPSC for a natural gas rate increase. Montana-Dakota requested a total increase of approximately $4.3 million annually or approximately 3.4 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, depreciation and taxes associated with the increased investment as well as an increase in Montana-Dakota's operation and maintenance expenses. Montana-Dakota requested an interim increase of $4.3 million or 3.4 percent, subject to refund, which was approved by the NDPSC on March 11, 2015, effective with service rendered on or after April 7, 2015. A technical hearing has been scheduled for July 20-21, 2015. This matter is pending before the NDPSC.

On March 31, 2015, Cascade filed an application with the OPUC for a natural gas rate increase. Cascade requested a total increase of approximately $3.6 million annually or approximately 5.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities and the associated operation and maintenance expenses, depreciation and taxes associated with the increase in investment, as well as environmental remediation expenses.

On April 10, 2015, Montana-Dakota submitted a request to the NDPSC to update the environmental cost recovery rider to reflect actual costs incurred through February 2015 and projected costs through June 2016 related to the recovery of Montana-Dakota's share of the costs resulting from the environmental retrofit required to be installed at the Big Stone Station. The request also includes costs associated with the environmental upgrade required at the Lewis & Clark Station to comply with the EPA's MATS rule. The filing also requests a revision to the environmental cost recovery rider that will allow future recovery of ongoing reagent costs required to meet environmental standards as a monthly adjustment. A total of $8.1 million is requested to be recovered under the adjustment. If approved, the rates would be effective July 1, 2015, through June 30, 2016.

Note 18 - Contingencies
The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss. The Company had accrued liabilities of $25.8 million, $31.4 million and $27.6 million for contingencies, including litigation, production taxes, royalty claims and environmental matters at March 31, 2015 and 2014, and December 31, 2014, respectively, which include amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.

Litigation
Natural Gas Gathering Operations In January 2010, SourceGas filed an application with the Colorado State District Court to compel WBI Energy Midstream to arbitrate a dispute regarding operating pressures under a natural gas gathering contract on one of WBI Energy Midstream's pipeline gathering systems in Montana. WBI Energy Midstream resisted the application and sought a declaratory order interpreting the gathering contract. In May 2010, the Colorado State District Court granted the application and ordered WBI Energy Midstream into arbitration. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. On remand of the matter to the Colorado State District Court, SourceGas may assert claims similar to those asserted in the arbitration proceeding.


24



In a related matter, Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a separate gathering contract with Omimex as a result of the increased operating pressures demanded by SourceGas on the same natural gas gathering system. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. The parties subsequently settled the breach of contract claim and, subject to final determination on liability, stipulated to the damages on the common carrier claim, for amounts that are not material. A trial on the common carrier claim was held during July 2013. On December 9, 2014, the United States District Court for the District of Montana issued an order determining WBI Energy Midstream breached its obligations as a common carrier and ordered judgment in favor of Omimex for the amount of the stipulated damages. WBI Energy Midstream filed an appeal from the United States District Court for the District of Montana's order and judgment.

Exploration and Production During the ordinary course of its business, Fidelity is subject to audit for various production related taxes by certain state and federal tax authorities for varying periods as well as claims for royalty obligations under lease agreements for oil and gas production. Disputes may exist regarding facts and questions of law relating to the tax and royalty obligations.

On May 15, 2013, Austin Holdings, LLC filed an action against Fidelity in Wyoming State District Court alleging Fidelity violated the Wyoming Royalty Payment Act and implied lease covenants by deducting production costs from and by failing to properly report and pay royalties for coalbed methane gas production in Wyoming. The plaintiff, in addition to declaratory and injunctive relief, seeks class certification for similarly situated persons and an unspecified amount of monetary damages on behalf of the class for unpaid royalties, interest, reporting violations and attorney fees. The Company reached a settlement of the matter, subject to final court approval, for an amount that is not material.

Construction Materials Until the fall of 2011 when it discontinued active mining operations at the pit, JTL operated the Target Range Gravel Pit in Missoula County, Montana under a 1975 reclamation contract pursuant to the Montana Opencut Mining Act. In September 2009, the Montana DEQ sent a letter asserting JTL was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL filed a complaint in Montana First Judicial District Court in June 2010, seeking a declaratory order that the reclamation contract is a valid permit under the Montana Opencut Mining Act. The Montana DEQ filed an answer and counterclaim to the complaint in August 2011, alleging JTL was in violation of the Montana Opencut Mining Act and requesting imposition of penalties of not more than $3.7 million plus not more than $5,000 per day from the date of the counterclaim. The Company believes the operation of the Target Range Gravel Pit was conducted under a valid permit; however, the imposition of civil penalties is reasonably possible. The Company filed an application for amendment of its opencut mining permit and intends to resolve this matter through settlement or continuation of the Montana First Judicial District Court litigation.

Former Employee Litigation On August 6, 2012, a former employee and his spouse filed actions against Connolly-Pacific and others in California Superior Court alleging the former employee contracted acute myelogenous leukemia from exposure to substances while employed as a seaman by the defendants. The plaintiffs request compensatory damages of approximately $23.8 million plus punitive damages, costs and interest. Connolly-Pacific is contesting the claims and believes it has meritorious defenses to them. Connolly-Pacific will seek insurance coverage for defense costs and any liability incurred in the litigation.

Construction Services Bombard Mechanical is a third-party defendant in litigation pending in Nevada State District Court in which the plaintiff claims damages attributable to defects in the construction of a 48 story residential tower built in 2008 for which Bombard Mechanical performed plumbing and mechanical work as a subcontractor. On March 12, 2015, the plaintiff submitted cost of repair estimates totaling approximately $26 million for alleged defects related to plumbing and mechanical system defects. Bombard Mechanical is being defended in the action under a policy of insurance subject to a reservation of rights.

The Company also is subject to other litigation, and actual and potential claims in the ordinary course of its business which may include, but are not limited to, matters involving property damage, personal injury, and environmental, contractual, statutory and regulatory obligations. Accruals are based on the best information available but actual losses in future periods are affected by various factors making them uncertain. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above issues and other probable and reasonably possible losses in excess of the amounts accrued, while uncertain, will not have a material effect upon the Company's financial position, results of operations or cash flows.


25



Environmental matters
Portland Harbor Site In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by Knife River - Northwest from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Portland Harbor Natural Resource Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.

Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, Knife River - Northwest does not believe it is a Responsible Party. In addition, Knife River - Northwest has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. Knife River - Northwest has entered into an agreement tolling the statute of limitations in connection with the LWG's potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest cannot demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, Knife River - Northwest has agreed to participate in the alternative dispute resolution process.

The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action.

Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors.

The first claim is for contamination at a site in Eugene, Oregon which was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. The Oregon DEQ released a ROD in January 2015 that selected a remediation alternative for the site as recommended in an earlier staff report. It is not known at this time what share of the cleanup costs will actually be borne by Cascade; however, Cascade anticipates its proportional share could be approximately 50 percent. Cascade has accrued $1.7 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. Cascade received orders reauthorizing the deferred accounting for the 12-month periods starting November 30, 2013 and December 1, 2014.

The second claim is for contamination at a site in Bremerton, Washington which was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. In April 2010, the Washington Department of Ecology issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List of Superfund sites. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $12.4 million for the remedial investigation, feasibility study and remediation of this site. In April 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.


26



The third claim is for contamination at a site in Bellingham, Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order and work plan with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. A report documenting the initial phase of the remedial investigation was completed in June 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas.

Cascade has received notices from and entered into agreement with certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers. The accruals related to these matters are reflected in regulatory assets.

Guarantees
In connection with the sale of the Brazilian Transmission Lines, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines.

WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of derivative activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap agreements at March 31, 2015, expire in 2015; however, Fidelity may continue to enter into additional derivative instruments and, as a result, WBI Holdings from time to time may issue additional guarantees on these derivative instruments. There were no amounts outstanding by Fidelity at March 31, 2015. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.

Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts and certain other guarantees. At March 31, 2015, the fixed maximum amounts guaranteed under these agreements aggregated $76.8 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $42.6 million in 2015; $14.5 million in 2016; $1.2 million in 2017; $500,000 in 2018; $500,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at March 31, 2015. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.

Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At March 31, 2015, the fixed maximum amounts guaranteed under these letters of credit, aggregated $42.5 million. In 2015 and 2016, $14.3 million and $28.2 million, respectively, of letters of credit are scheduled to expire. The amount outstanding by subsidiaries of the Company under the above letters of credit was $300,000 and was reflected on the Consolidated Balance Sheet at March 31, 2015. In the event of default under these letter of credit obligations, the subsidiary issuing the letter of credit for that particular obligation would be required to make payments under its letter of credit.

Centennial and WBI Holdings have guaranteed certain debt obligations of Dakota Prairie Refining. For more information, see Variable interest entities in this note.

WBI Holdings has an outstanding guarantee to WBI Energy Transmission. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At March 31, 2015, the fixed maximum amount guaranteed under this agreement was $4.0 million and is scheduled to expire in 2016. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $1.1 million. The amount outstanding under this guarantee was not

27



reflected on the Consolidated Balance Sheet at March 31, 2015, because this intercompany transaction was eliminated in consolidation.

In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under these obligations, Centennial, Knife River and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at March 31, 2015.

In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. At March 31, 2015, approximately $536.7 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.

Variable interest entities
The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary.

Dakota Prairie Refining, LLC On February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate Dakota Prairie Refinery in southwestern North Dakota. WBI Energy and Calumet each have a 50 percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments, based on a total project cost of $300 million, under the agreement are $150 million and $75 million, respectively. Capital commitments in excess of $300 million are being shared equally between WBI Energy and Calumet. The total project cost is currently estimated at approximately $425 million to $435 million. Dakota Prairie Refining entered into a term loan for project debt financing of $75 million on April 22, 2013. The operating agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the operating agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan.

On December 1, 2014, Dakota Prairie Refining entered into a $50 million revolving credit agreement with an expiration date of December 1, 2015. Pursuant to the revolving credit agreement, WBI Holdings has guaranteed 50 percent of the credit agreement and Calumet has issued a letter of credit supporting 50 percent of the credit agreement. The credit agreement is used to meet the operational needs of the facility.

Dakota Prairie Refining has been determined to be a VIE, and the Company has determined that it is the primary beneficiary as it has an obligation to absorb losses that could be potentially significant to the VIE through WBI Energy's equity investment and Centennial's guarantee of the third-party term loan. Accordingly, the Company consolidates Dakota Prairie Refining in its financial statements and records a noncontrolling interest for Calumet's ownership interest.

Dakota Prairie Refinery has commenced operations. The facility has begun producing diesel fuel and is expected to begin sales of diesel during May 2015. The assets of Dakota Prairie Refining shall be used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets were as follows:

28



 
March 31, 2015
March 31, 2014
December 31, 2014
 
(In thousands)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
10,784

$
22,996

$
21,376

Accounts receivable
2,335


2,759

Inventories
7,902


5,311

Other current assets
2,926

1,135

4,019

Total current assets
23,947

24,131

33,465

Net property, plant and equipment
425,944

207,260

398,984

Deferred charges and other assets:
 
 
 
Other
4,562


3,400

Total deferred charges and other assets
4,562


3,400

Total assets
$
454,453

$
231,391

$
435,849

LIABILITIES
 
 
 
Current liabilities:
 
 
 
Short-term borrowings
$
16,100

$

$

Long-term debt due within one year
3,000

3,000

3,000

Accounts payable
23,654

16,103

55,089

Taxes payable
569

113

648

Accrued compensation
683

164

727

Other accrued liabilities
1,016

580

899

Total current liabilities
45,022

19,960

60,363

Long-term debt
69,000

72,000

69,000

Total liabilities
$
114,022

$
91,960

$
129,363


Fuel Contract On October 10, 2012, the Coyote Station entered into a new coal supply agreement with Coyote Creek that will replace a coal supply agreement expiring in May 2016. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040.

The new coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so the price of the coal will cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station, with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements.

At March 31, 2015, Coyote Creek was not yet operational. The assets and liabilities of Coyote Creek and exposure to loss as a result of the Company's involvement with the VIE, based on the Company's ownership percentage, at March 31, 2015, was $20.8 million.


29



ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview
The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through:

Organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties
The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization
The development of projects that are accretive to earnings per share and return on invested capital
Divestiture of certain assets to fund capital growth projects throughout the Company

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities, revolving credit facilities, the issuance from time to time of debt and equity securities and asset sales. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.

The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a summary of the Company's business segments, see Note 15.

Key Strategies and Challenges
Electric and Natural Gas Distribution
Strategy Provide safe and reliable competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation and transmission and natural gas systems, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment.

Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and timely recovery and permitted returns on investment as well as subject to certain operational, system integrity and environmental regulations. These regulations can require substantial investment to upgrade facilities. The ability of these segments to grow through acquisitions is subject to significant competition. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and competition from other energy providers and fuels. The construction of any new electric generating facilities, transmission lines and other service facilities are subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which will necessitate increases in electric energy prices. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas.

Pipeline and Energy Services
Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, investments in and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; incremental expansion of pipeline capacity; expansion of midstream business to include liquid pipelines and processing/refining activities; and expansion of related energy services.

Challenges Challenges for this segment include: energy price volatility; tight natural gas basis differentials; environmental and regulatory requirements; recruitment and retention of a skilled workforce; and competition from other pipeline and energy services companies.

Exploration and Production
Strategy The Company intends to market and sell its exploration and production business. However, the Company has delayed its plan in light of the recent volatility in oil prices. Until such sale is accomplished, this segment will apply technology and utilize existing expertise to increase production and reserves from existing leaseholds. By optimizing existing operations, this segment is focused on balancing its oil and natural gas commodity mix to maximize profitability.


30



Challenges Risks and uncertainties associated with the marketing and sale of the Fidelity assets; current oil and natural gas low-price environment; timely receipt of necessary permits and approvals; environmental and regulatory requirements; recruitment and retention of a skilled workforce; utilizing appropriate technologies; inflationary pressure on development and operating costs; irregularities in geological formations; and competition from other exploration and production companies are ongoing challenges for this segment.

Construction Materials and Contracting
Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; develop and recruit talented employees; and continue growth through organic and acquisition opportunities. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.

Challenges Recruitment and retention of key personnel and volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, continue to be a concern. This business unit expects to continue cost containment efforts, positioning its operations for the resurgence in the private market, while continuing the emphasis on industrial, energy and public works projects.

Construction Services
Strategy Provide a superior return on investment by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; continue growth through organic and acquisition opportunities; and focusing our efforts on projects that will permit higher margins while properly managing risk.

Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing through downturns in the economy and effective management of working capital are ongoing challenges.

For more information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2014 Annual Report. For more information on key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements.

Earnings Overview
The following table summarizes the contribution to consolidated earnings (loss) by each of the Company's businesses.

 
Three Months Ended
 
March 31,
 
2015

2014

 
(Dollars in millions, where applicable)
Electric
$
8.3

$
11.0

Natural gas distribution
21.5

27.3

Pipeline and energy services
4.0

4.3

Exploration and production
(328.9
)
20.9

Construction materials and contracting
(14.6
)
(23.6
)
Construction services
4.8

16.6

Other
(.3
)
.3

Intersegment eliminations
(.9
)
(.3
)
Earnings (loss) on common stock
$
(306.1
)
$
56.5

Earnings (loss) per common share – basic
$
(1.57
)
$
.30

Earnings (loss) per common share – diluted
$
(1.57
)
$
.30



31



Three Months Ended March 31, 2015 and 2014 Consolidated earnings for the quarter ended March 31, 2015, decreased $362.6 million from the comparable prior period largely due to:
A noncash write-down of oil and natural gas properties of $315.3 million (after tax); lower average realized commodity prices, excluding gain/loss on commodity derivatives; and decreased oil production; partially offset by a favorable adjustment related to realized gain/loss on commodity derivatives at the exploration and production business
Lower workloads and margins in the Western region at the construction services business
Lower earnings related to decreased retail sales volumes at the natural gas distribution business

Partially offsetting these decreases were lower seasonal losses resulting from higher construction revenues and margins, as well as higher aggregate and ready-mixed concrete margins and volumes at the construction materials and contracting business.

FINANCIAL AND OPERATING DATA
Below are key financial and operating data for each of the Company's businesses.

Electric

 
Three Months Ended
 
March 31,
 
2015

2014

 
(Dollars in millions, where applicable)
Operating revenues
$
71.8

$
73.7

Operating expenses:
 

 

Fuel and purchased power
23.8

26.6

Operation and maintenance
21.1

18.4

Depreciation, depletion and amortization
9.4

8.5

Taxes, other than income
3.1

2.9

 
57.4

56.4

Operating income
14.4

17.3

Earnings
$
8.3

$
11.0

Retail sales (million kWh)
907.7

928.9

Average cost of fuel and purchased power per kWh
$
.025

$
.027

Three Months Ended March 31, 2015 and 2014 Electric earnings decreased $2.7 million (25 percent) due to:
Higher operation and maintenance expense, which includes $1.7 million (after tax) largely due to higher contract services, primarily related to a planned outage at an electric generation station
Higher net interest expense, which includes $900,000 (after tax) largely related to higher long-term debt
Higher depreciation, depletion and amortization expense of $500,000 (after tax) due to increased property, plant and equipment balances

Partially offsetting these decreases were increased retail sales margins, primarily due to rate recovery of generation and environmental upgrades, reduced in part by decreased sales volumes of 2 percent, primarily to residential customers.


32



Natural Gas Distribution

 
Three Months Ended
 
March 31,
 
2015

2014

 
(Dollars in millions, where applicable)
Operating revenues
$
330.6

$
374.2

Operating expenses:
 

 

Purchased natural gas sold
222.2

257.3

Operation and maintenance
38.4

37.9

Depreciation, depletion and amortization
14.6