Attached files

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EX-31.B - MDU RESOURCES CERTIFICATION OF CHIEF FINANCIAL OFFICER - MDU RESOURCES GROUP INCa2016q1ex31b.htm
EX-32 - MDU RESOURCES CERTIFICATION OF CEO AND CFO - MDU RESOURCES GROUP INCa2016q1ex32.htm
EX-10.E - MDU RESOURCES SECTION 16 OFFICERS AND DIRECTORS - MDU RESOURCES GROUP INCa2016q1ex10e.htm
EX-95 - MDU RESOURCES MINE SAFETY DISCLOSURES - MDU RESOURCES GROUP INCa2016q1ex95.htm
EX-10.C - MDU RESOURCES 401 K RETIREMENT PLAN AMENDMENT 1-22-2016 - MDU RESOURCES GROUP INCa2016q1ex10c.htm
EX-12 - MDU RESOURCES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - MDU RESOURCES GROUP INCa2016q1ex12.htm
EX-10.B - MDU RESOURCES EXECUTIVE INCENTIVE COMPENSATION PLAN AMENDED 2-11-2016 - MDU RESOURCES GROUP INCa2016q1ex10b.htm
EX-31.A - MDU RESOURCES CERTIFICATION OF CHIEF EXECUTIVE OFFICER - MDU RESOURCES GROUP INCa2016q1ex31a.htm
EX-10.A - MDU RESOURCES SUPPLEMENTAL INCOME SECURITY PLAN 2-11-2016 - MDU RESOURCES GROUP INCa2016q1ex10a.htm
EX-10.D - MDU RESOURCES 401 K RETIREMENT PLAN AMENDMENT 3-10-2016 - MDU RESOURCES GROUP INCa2016q1ex10d.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, 2016
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to ______________
Commission file number 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 definitions 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 (Do not check if a smaller reporting company)
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý.
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of April 29, 2016: 195,304,376 shares.





Definitions
The following abbreviations and acronyms used in this Form 10-Q are defined below:
Abbreviation or Acronym
 
2015 Annual Report
Company's Annual Report on Form 10-K for the year ended December 31, 2015
AFUDC
Allowance for funds used during construction
ASC
FASB Accounting Standards Codification
ATBs
Atmospheric tower bottoms
Bbl
Barrel
Bombard Mechanical
Bombard Mechanical, LLC, an indirect wholly owned subsidiary of MDU Construction Services
BPD
Barrels per day
Brazilian Transmission Lines
Company's former investment in companies owning three electric transmission lines
Btu
British thermal unit
Calumet
Calumet Specialty Products Partners, L.P.
Cascade
Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
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
Company
MDU Resources Group, Inc.
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
D.C. Circuit Court
United States Court of Appeals for the District of Columbia Circuit
dk
Decatherm
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act
EPA
United States Environmental Protection Agency
ERISA
Employee Retirement Income Security Act of 1974
ESCP
Erosion and Sediment Control Plan
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fidelity
Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings (previously referred to as the Company's exploration and production segment)
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
IFRS
International Financial Reporting Standards
Intermountain
Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
JTL - Montana
JTL Group, Inc. (Montana Corporation), an indirect wholly owned subsidiary of Knife River
JTL - Wyoming
JTL Group, Inc. (Wyoming Corporation), 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
LTM
LTM, Incorporated, an indirect wholly owned subsidiary of Knife River
LWG
Lower Willamette Group
MBbls
Thousands of barrels

2



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
MMdk
Million dk
MNPUC
Minnesota Public Utilities Commission
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
Notice of Civil Penalty
Notice of Civil Penalty Assessment and Order
Oil
Includes crude oil and condensate
Omimex
Omimex Canada, Ltd.
OPUC
Oregon Public Utility Commission
Oregon DEQ
Oregon State Department of Environmental Quality
PRP
Potentially Responsible Party
RIN
Renewable Identification Number
ROD
Record of Decision
RP
Rehabilitation plan
SDPUC
South Dakota Public Utilities Commission
SEC
United States 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
United States District Court for the District of Montana
United States District Court for the District of Montana, Great Falls Division
United States Supreme Court
Supreme Court of the United States
VIE
Variable interest entity
Washington DOE
Washington State Department of Ecology
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

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 midstream segment, the refining segment and Fidelity, formerly the Company's exploration and production business), Knife River (construction materials and contracting segment), MDU Construction Services (construction services segment), Centennial Resources and Centennial Capital (both reflected in the Other category).
In the second quarter of 2015, the Company announced its plan to market Fidelity and exit that line of business. The Company completed the sale of all of its marketed assets. Therefore, the results of Fidelity are reflected in discontinued operations, other than certain general and administrative costs and interest expense which are reflected in the Other category. For more information on the Company's business segments and discontinued operations, see Notes 9 and 14.


4



Index
Part I -- Financial Information
Page
 
 
Consolidated Statements of Income --
Three Months Ended March 31, 2016 and 2015
 
 
Consolidated Statements of Comprehensive Income --
Three Months Ended March 31, 2016 and 2015
 
 
Consolidated Balance Sheets --
March 31, 2016 and 2015, and December 31, 2015
 
 
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2016 and 2015
 
 
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
 
 
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
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,
 
2016

2015

 
(In thousands, except per share amounts)
Operating revenues:
 
 
Electric, natural gas distribution and regulated pipeline and midstream
$
385,738

$
406,289

Nonregulated pipeline and midstream, construction materials and contracting, construction services, refining and other
519,415

456,060

Total operating revenues 
905,153

862,349

Operating expenses:
 

 

Fuel and purchased power
22,011

23,819

Purchased natural gas sold
161,035

201,150

Cost of crude oil
39,800

2,270

Operation and maintenance:
 

 

Electric, natural gas distribution and regulated pipeline and midstream
74,498

68,343

Nonregulated pipeline and midstream, construction materials and contracting, construction services, refining and other
461,784

428,100

Depreciation, depletion and amortization
60,259

52,998

Taxes, other than income
44,014

42,000

Total operating expenses
863,401

818,680

Operating income
41,752

43,669

Other income
1,246

443

Interest expense
23,776

23,127

Income before income taxes
19,222

20,985

Income taxes
4,558

5,825

Income from continuing operations
14,664

15,160

Loss from discontinued operations, net of tax (Note 9)
(835
)
(324,605
)
Net income (loss)
13,829

(309,445
)
Net loss attributable to noncontrolling interest
(11,040
)
(3,528
)
Dividends declared on preferred stocks
171

171

Earnings (loss) on common stock
$
24,698

$
(306,088
)
Earnings (loss) per common share - basic:
 

 

Earnings before discontinued operations
$
.13

$
.10

Discontinued operations, net of tax

(1.67
)
Earnings (loss) per common share - basic
$
.13

$
(1.57
)
Earnings (loss) per common share - diluted:
 

 

Earnings before discontinued operations
$
.13

$
.10

Discontinued operations, net of tax

(1.67
)
Earnings (loss) per common share - diluted
$
.13

$
(1.57
)
Dividends declared per common share
$
.1875

$
.1825

Weighted average common shares outstanding - basic
195,284

194,479

Weighted average common shares outstanding - diluted
195,284

194,566

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,
 
2016
2015
 
(In thousands)
Net income (loss)
$
13,829

$
(309,445
)
Other comprehensive income (loss):
 
 
Reclassification adjustment for loss on derivative instruments included in net income (loss), net of tax of $57 and $60 for the three months ended in 2016 and 2015, respectively
92

99

Amortization of postretirement liability (gains) losses included in net periodic benefit cost, net of tax of $(969) and $230 for the three months ended in 2016 and 2015, respectively
(1,595
)
375

Foreign currency translation adjustment:
 
 
Foreign currency translation adjustment recognized during the period, net of tax of $15 and $(68) for the three months ended in 2016 and 2015, respectively
25

(112
)
Reclassification adjustment for loss on foreign currency translation adjustment included in net income (loss), net of tax of $0 and $490 for the three months ended in 2016 and 2015, respectively

802

Foreign currency translation adjustment
25

690

Net unrealized gain on available-for-sale investments:
 
 
Net unrealized gain (loss) on available-for-sale investments arising during the period, net of tax of $5 and $(11) for the three months ended in 2016 and 2015, respectively
8

(21
)
Reclassification adjustment for loss on available-for-sale investments included in net income (loss), net of tax of $19 and $19 for the three months ended in 2016 and 2015, respectively
36

36

Net unrealized gain on available-for-sale investments
44

15

Other comprehensive income (loss)
(1,434
)
1,179

Comprehensive income (loss)
12,395

(308,266
)
Comprehensive loss attributable to noncontrolling interest
(11,040
)
(3,528
)
Comprehensive income (loss) attributable to common stockholders
$
23,435

$
(304,738
)
The accompanying notes are an integral part of these consolidated financial statements.



7



MDU Resources Group, Inc.
Consolidated Balance Sheets
(Unaudited)
 
March 31, 2016
March 31, 2015
December 31, 2015
(In thousands, except shares and per share amounts)
 
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
90,938

$
126,440

$
84,591

Receivables, net
537,744

505,964

590,105

Inventories
276,812

328,072

253,727

Deferred income taxes
33,868

37,385

32,849

Prepayments and other current assets
57,821

80,905

35,059

Current assets held for sale
57,753

91,205

24,581

Total current assets
1,054,936

1,169,971

1,020,912

Investments
121,955

118,370

119,704

Property, plant and equipment
6,878,595

6,367,988

6,817,668

Less accumulated depreciation, depletion and amortization
2,543,942

2,412,060

2,506,571

Net property, plant and equipment
4,334,653

3,955,928

4,311,097

Deferred charges and other assets:
 

 

 

Goodwill
641,527

635,204

635,204

Other intangible assets, net
7,803

9,166

7,342

Other
359,977

319,627

360,546

Noncurrent assets held for sale
97,549

1,113,529

166,734

Total deferred charges and other assets 
1,106,856

2,077,526

1,169,826

Total assets
$
6,618,400

$
7,321,795

$
6,621,539

Liabilities and Equity
 

 

 

Current liabilities:
 

 

 

Short-term borrowings
$
61,525

$
16,100

$
45,500

Long-term debt due within one year
104,915

408,539

243,789

Accounts payable
260,432

209,456

310,466

Taxes payable
50,222

44,282

45,775

Dividends payable
36,791

35,687

36,784

Accrued compensation
41,137

34,905

46,130

Other accrued liabilities
189,275

164,151

171,592

Current liabilities held for sale
17,170

82,313

47,603

Total current liabilities 
761,467

995,433

947,639

Long-term debt
1,822,139

1,775,105

1,621,374

Deferred credits and other liabilities:
 

 

 

Deferred income taxes
728,304

736,731

720,319

Other liabilities
811,106

757,233

811,659

Noncurrent liabilities held for sale

122,850


Total deferred credits and other liabilities 
1,539,410

1,616,814

1,531,978

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 - 195,843,297 at March 31, 2016, 195,191,129 at
March 31, 2015 and 195,804,665 at December 31, 2015
195,843

195,191

195,805

Other paid-in capital
1,229,431

1,214,867

1,230,119

Retained earnings
984,315

1,421,220

996,355

Accumulated other comprehensive loss
(38,582
)
(40,924
)
(37,148
)
Treasury stock at cost - 538,921 shares
(3,626
)
(3,626
)
(3,626
)
Total common stockholders' equity
2,367,381

2,786,728

2,381,505

Total stockholders' equity
2,382,381

2,801,728

2,396,505

Noncontrolling interest
113,003

132,715

124,043

Total equity
2,495,384

2,934,443

2,520,548

Total liabilities and equity 
$
6,618,400

$
7,321,795

$
6,621,539

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,
 
2016

2015

 
(In thousands)
Operating activities:
 
 
Net income (loss)
$
13,829

$
(309,445
)
Loss from discontinued operations, net of tax
(835
)
(324,605
)
Income from continuing operations
14,664

15,160

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

 

Depreciation, depletion and amortization
60,259

52,998

Deferred income taxes
6,902

16,301

Changes in current assets and liabilities, net of acquisitions:
 

 
Receivables
58,435

83,544

Inventories
(22,298
)
(47,283
)
Other current assets
(22,730
)
4,021

Accounts payable
(37,205
)
(34,696
)
Other current liabilities
13,800

(10,839
)
Other noncurrent changes
(4,047
)
(5,043
)
Net cash provided by continuing operations
67,780

74,163

Net cash provided by (used in) discontinued operations
(22,554
)
24,697

Net cash provided by operating activities
45,226

98,860

Investing activities:
 

 

Capital expenditures
(115,194
)
(135,295
)
Net proceeds from sale or disposition of property and other
10,456

25,029

Investments
(503
)
1,593

Net cash used in continuing operations
(105,241
)
(108,673
)
Net cash provided by (used in) discontinued operations
25,706

(51,540
)
Net cash used in investing activities
(79,535
)
(160,213
)
Financing activities:
 

 

Issuance of short-term borrowings
16,025

16,100

Issuance of long-term debt
226,585

149,332

Repayment of long-term debt
(164,855
)
(54,019
)
Proceeds from issuance of common stock

9,864

Dividends paid
(36,784
)
(35,607
)
Tax withholding on stock-based compensation
(316
)

Contribution from noncontrolling interest

20,500

Net cash provided by continuing operations
40,655

106,170

Net cash used in discontinued operations

(143
)
Net cash provided by financing activities
40,655

106,027

Effect of exchange rate changes on cash and cash equivalents
1

(89
)
Increase in cash and cash equivalents
6,347

44,585

Cash and cash equivalents -- beginning of year
84,591

81,855

Cash and cash equivalents -- end of period
$
90,938

$
126,440

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

9



MDU Resources Group, Inc.
Notes to Consolidated
Financial Statements
March 31, 2016 and 2015
(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 2015 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 2015 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, 2016, up to the date of issuance of these consolidated interim financial statements.
In the second quarter of 2015, the Company began the marketing and sale process of Fidelity with an anticipated sale to occur within one year. Between September 2015 and March 2016, the Company entered into purchase and sale agreements to sell all of Fidelity's marketed oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. The sale of Fidelity was part of the Company's strategic plan to grow its capital investments in the remaining business segments and to focus on creating a greater long-term value. The assets and liabilities for these operations have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated. At the time the assets were classified as held for sale, depreciation, depletion and amortization expense was no longer recorded. Unless otherwise indicated, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company's continuing operations. For more information on discontinued operations, see Note 9.
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 $30.5 million, $27.7 million and $27.8 million at March 31, 2016 and 2015, and December 31, 2015, 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, 2016 and 2015, and December 31, 2015, was $11.1 million, $9.4 million and $9.8 million, respectively.
Note 4 - Inventories and natural gas in storage
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. Crude oil and refined products at Dakota Prairie Refinery are carried at lower of cost or market value using the last-in, first-out method. All other inventories are stated at the lower of average cost or market value. The portion of the cost of natural gas in storage expected to be used within one year is included in inventories. Inventories consisted of:

10



 
March 31, 2016

March 31, 2015

December 31, 2015

 
(In thousands)
Aggregates held for resale
$
127,101

$
112,029

$
115,854

Asphalt oil
52,065

89,578

36,498

Natural gas in storage (current)
11,305

9,303

21,023

Materials and supplies
21,645

57,073

16,997

Merchandise for resale
17,441

15,688

15,318

Crude oil
3,034

7,076

4,678

Refined products
14,022


8,498

Other
30,199

37,325

34,861

Total
$
276,812

$
328,072

$
253,727

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 $49.1 million, $49.3 million and $49.1 million at March 31, 2016 and 2015, and December 31, 2015, respectively.
Note 5 - 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 (loss) per common share were computed by dividing earnings (loss) 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. 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:
 
Three Months Ended
 
March 31,
 
2016

2015

 
(In thousands)
Weighted average common shares outstanding - basic
195,284

194,479

Effect of dilutive performance share awards

87

Weighted average common shares outstanding - diluted
195,284

194,566

Shares excluded from the calculation of diluted earnings per share


Note 6 - Cash flow information
Cash expenditures for interest and income taxes were as follows:
 
Three Months Ended
 
March 31,
 
2016

2015

 
(In thousands)
Interest, net of amounts capitalized and AFUDC - borrowed of $260,000 and $2.6 million in 2016 and 2015, respectively
$
23,830

$
23,852

Income taxes refunded, net
$
(1,429
)
$
(11,216
)
Noncash investing transactions were as follows:
 
March 31,
 
2016

2015

 
(In thousands)
Property, plant and equipment additions in accounts payable
$
30,232

$
29,575

Note 7 - 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 was to be effective for the Company on January 1, 2017. In August 2015, the FASB issued guidance deferring the effective date of the revenue guidance one year and allowing entities to early adopt. With this decision, the guidance will be effective for the Company on January 1, 2018. Entities will have the option of using either a full retrospective or modified

11



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 was effective for the Company on January 1, 2016, and is to be applied retrospectively. Early adoption of this guidance was permitted, however the Company did not elect to do so. The guidance required a reclassification of the debt issuance costs on the Consolidated Balance Sheets, but did not impact the Company's results of operations or cash flows. As a result of the retrospective application of this change in accounting principle, the Company reclassified debt issuance costs of $100,000 and $100,000 from prepayments and other current assets and $5.5 million and $6.0 million from other deferred charges and other assets to long-term debt on its Consolidated Balance Sheets at March 31, 2015 and December 31, 2015, respectively.
Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) In May 2015, the FASB issued guidance on fair value measurement and disclosure requirements removing the requirement to include investments in the fair value hierarchy for which fair value is measured using the net asset value per share practical expedient. The new guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at net asset value using the practical expedient, and rather limits those disclosures to investments for which the practical expedient has been elected. This guidance was effective for the Company on January 1, 2016, with early adoption permitted. The application of this guidance affected the Company's disclosures, however it did not impact the Company's results of operations, financial position or cash flows.
Simplifying the Measurement of Inventory In July 2015, the FASB issued guidance regarding inventory that is measured using the first-in, first-out or average cost method. The guidance does not apply to inventory measured using the last-in, first-out or the retail inventory method. The guidance requires inventory within its scope to be measured at the lower of cost or net realizable value, which is the estimated selling price in the normal course of business less reasonably predictable costs of completion, disposal and transportation. These amendments more closely align GAAP with IFRS. This guidance will be effective for the Company on January 1, 2017, and should be applied prospectively with early adoption permitted as of the beginning of an interim or annual reporting period. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position and cash flows.
Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. The guidance will require all deferred tax assets and liabilities to be classified as noncurrent. These amendments will align GAAP with IFRS. This guidance will be effective for the Company on January 1, 2017, with early adoption permitted. Entities will have the option to apply the guidance prospectively, for all deferred tax assets and liabilities, or retrospectively. The Company is evaluating the effects the adoption of the new guidance will have on its financial position and disclosures, however it will not impact the Company's results of operations or cash flows.
Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued guidance regarding the classification and measurement of financial instruments. The guidance revises the way an entity classifies and measures investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value and amends certain disclosure requirements related to the fair value of financial instruments. This guidance will be effective for the Company on January 1, 2018, with early adoption of certain amendments permitted. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.
Leases In February 2016, the FASB issued guidance regarding leases. The guidance requires lessees to recognize a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the statement of financial position for leases with terms of more than 12 months. This guidance also requires additional disclosures. This guidance will be effective for the Company on January 1, 2019, and should be applied using a modified retrospective approach with early adoption permitted. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.
Improvements to Employee Share-Based Payment Accounting In March 2016, the FASB issued guidance regarding simplification of several aspects of the accounting for share-based payment transactions. The guidance will affect the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This guidance will be effective for the Company on January 1, 2017, with early adoption permitted in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period. Certain amendments of this guidance are to be applied retrospectively and others prospectively. The Company is evaluating the effects the adoption of the new guidance will have on its results of operations, financial position, cash flows and disclosures.


12



Note 8 - Comprehensive income (loss)
The after-tax changes in the components of accumulated other comprehensive loss were as follows:
Three Months Ended
March 31, 2016
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
$
(2,667
)
$
(34,257
)
$
(200
)
$
(24
)
$
(37,148
)
Other comprehensive income before reclassifications


25

8

33

Amounts reclassified from accumulated other comprehensive loss
92

(1,595
)

36

(1,467
)
Net current-period other comprehensive income (loss)
92

(1,595
)
25

44

(1,434
)
Balance at end of period
$
(2,575
)
$
(35,852
)
$
(175
)
$
20

$
(38,582
)
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 (loss)
99

375

690

15

1,179

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

$
(40,924
)
 
 
 
 
 
 
 
 
 
 
 
 
Reclassifications out of accumulated other comprehensive loss were as follows:
 
Three Months Ended
Location on Consolidated Statements of
Income
 
March 31,
 
2016
2015
 
(In thousands)
 
Reclassification adjustment for loss on derivative instruments included in net income (loss):
 
 
 
Interest rate derivative instruments
$
(149
)
$
(159
)
Interest expense
 
57

60

Income taxes
 
(92
)
(99
)
 
Amortization of postretirement liability gains (losses) included in net periodic benefit cost
2,564

(605
)
(a)
 
(969
)
230

Income taxes
 
1,595

(375
)
 
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
)
(55
)
Other income
 
19

19

Income taxes
 
(36
)
(36
)
 
Total reclassifications
$
1,467

$
(1,312
)
 
 (a) Included in net periodic benefit cost. For more information, see Note 15.
 

13



Note 9 - Discontinued operations
In the second quarter of 2015, the Company began the marketing and sale process of Fidelity with an anticipated sale to occur within one year. Between September 2015 and March 2016, the Company entered into purchase and sale agreements to sell all of Fidelity's marketed oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. The sale of Fidelity was part of the Company's strategic plan to grow its capital investments in the remaining business segments and to focus on creating a greater long-term value. The assets and liabilities for these operations have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. The Company's consolidated financial statements and accompanying notes for current and prior periods have been restated. At the time the assets were classified as held for sale, depreciation, depletion and amortization expense was no longer recorded.
The carrying amounts of the major classes of assets and liabilities that are classified as held for sale on the Company's Consolidated Balance Sheets were as follows:
 
March 31, 2016

March 31, 2015

December 31, 2015

 
(In thousands)
Assets
 
 
 
Current assets:
 
 
 
Receivables, net
$
3,619

$
58,125

$
13,387

Inventories
1,308

8,526

1,308

Commodity derivative instruments

7,127


Income taxes receivable
50,478

12,666

9,665

Prepayments and other current assets
2,348

4,761

221

Total current assets held for sale
57,753

91,205

24,581

Noncurrent assets:
 
 
 
Investments
37

37

37

Net property, plant and equipment
9,363

1,110,592

793,422

Deferred income taxes
86,614


127,655

Other
161

2,900

161

Less allowance for impairment of assets held for sale
(1,374
)

754,541

Total noncurrent assets held for sale
97,549

1,113,529

166,734

Total assets held for sale
$
155,302

$
1,204,734

$
191,315

Liabilities
 
 
 
Current liabilities:
 
 
 
Long-term debt due within one year
$

$
754

$

Accounts payable
7,963

54,623

25,013

Taxes payable
35

4,125

1,052

Deferred income taxes
3,620

4,398

3,620

Accrued compensation
761

2,891

13,080

Other accrued liabilities
4,791

15,522

4,838

Total current liabilities held for sale
17,170

82,313

47,603

Noncurrent liabilities:
 
 
 
Deferred income taxes

69,456


Asset retirement obligations

53,202


Other liabilities

192


Total noncurrent liabilities held for sale

122,850


Total liabilities held for sale
$
17,170

$
205,163

$
47,603

The Company performed a fair value assessment of the assets and liabilities classified as held for sale. In the first quarter of 2016, the fair value assessment was determined using the market approach largely based on a purchase and sale agreement. The estimated fair value exceeded the carrying value and the Company recorded an impairment reversal of $1.4 million ($900,000 after tax) in the first quarter of 2016. The impairment reversal was included in operating expenses from discontinued operations. The estimated fair value of Fidelity's assets have been categorized as Level 3 in the fair value hierarchy. In 2015, the Company recorded impairments totaling $754.5 million ($475.4 million after tax) related to the assets and liabilities classified as held for sale. For more information, see Part II, Item 8 - Note 2, in the 2015 Annual Report.
At March 31, 2016, the Company had accrued liabilities of approximately $300,000 for estimated transaction costs which will result in future cash expenditures. The Company incurred transaction costs of approximately $2.5 million in 2015. In addition to

14



the transaction costs, and due in part to the change in plans to sell the assets of Fidelity rather than sell Fidelity as a company, Fidelity incurred and expensed approximately $1.8 million of exit and disposal costs in the first quarter of 2016, and has incurred $6.7 million of exit and disposal costs to date. The Company expects to incur an additional $4.3 million of exit and disposal costs for the remainder of 2016. The exit and disposal costs are associated with severance and other related matters, excluding the office lease expiration discussed in the following paragraph. The majority of these exit and disposal activities are expected to be completed by the end of the second quarter of 2016.
Fidelity is vacating its office space in Denver, Colorado. An amendment of lease has been executed with payments of $3.7 million outstanding required under the lease amendment at March 31, 2016. The Company incurred approximately $500,000 of lease payments in the first quarter of 2016. A termination payment of $3.3 million was made during the fourth quarter of 2015 and existing office furniture and fixtures will be relinquished to the lessor in the second quarter of 2016.
Historically, the Company used 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 the units-of-production method based on total proved reserves.
Prior to the oil and natural gas properties being classified as held for sale, capitalized costs were 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, were used to calculate the ceiling test. Accordingly, the Company was required to write down its oil and natural gas producing properties. The Company recorded a $500.4 million ($315.3 million after tax) noncash write-down in operating expenses from discontinued operations in the first quarter of 2015.
The reconciliation of the major classes of income and expense constituting pretax loss from discontinued operations to the after-tax net loss from discontinued operations on the Company's Consolidated Statements of Income were as follows:
 
Three Months Ended
 
March 31,
 
2016

2015

 
(In thousands)
Operating revenues
$
2,910

$
54,936

Operating expenses
4,470

572,952

Operating loss
(1,560
)
(518,016
)
Other income
6

1,881

Interest expense
13

21

Loss from discontinued operations before income taxes
(1,567
)
(516,156
)
Income taxes
(732
)
(191,551
)
Loss from discontinued operations
$
(835
)
$
(324,605
)
Note 10 - Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Three Months Ended March 31, 2016
Balance as of
January 1, 2016

*
Goodwill Acquired
During the Year

Balance as of
March 31, 2016

*
 
(In thousands)
Natural gas distribution
$
345,736

 
$

$
345,736

 
Pipeline and midstream
9,737

 

9,737

 
Construction materials and contracting
176,290

 

176,290

 
Construction services
103,441

 
6,323

109,764

 
Total
$
635,204

 
$
6,323

$
641,527

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

15



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 midstream
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 midstream segment, which occurred in prior periods.

Year Ended December 31, 2015
Balance as of
January 1, 2015

*
Goodwill Acquired
During the Year

Balance as of
December 31, 2015

*
 
(In thousands)
Natural gas distribution
$
345,736

 
$

$
345,736

 
Pipeline and midstream
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 midstream segment, which occurred in prior periods.
 
Other amortizable intangible assets were as follows:
 
March 31, 2016

March 31, 2015

December 31, 2015

 
(In thousands)
Customer relationships
$
17,145

$
20,975

$
20,975

Accumulated amortization
(12,680
)
(15,649
)
(16,845
)
 
4,465

5,326

4,130

Noncompete agreements
2,430

4,409

4,409

Accumulated amortization
(1,548
)
(3,504
)
(3,655
)
 
882

905

754

Other
7,764

8,300

8,304

Accumulated amortization
(5,308
)
(5,365
)
(5,846
)
 
2,456

2,935

2,458

Total
$
7,803

$
9,166

$
7,342

Amortization expense for amortizable intangible assets for the three months ended March 31, 2016 and 2015, was $600,000 and $700,000, respectively. Estimated amortization expense for amortizable intangible assets is $2.5 million in 2016, $2.2 million in 2017, $1.2 million in 2018, $1.0 million in 2019, $500,000 in 2020 and $1.0 million thereafter.
Note 11 - 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, 2016, the Company had no outstanding commodity, 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.
Fidelity
At March 31, 2015, Fidelity held oil swap agreements with total forward notional volumes of 958,000 Bbl and natural gas swap agreements with total forward notional volumes of 2.8 million MMBtu. At March 31, 2016 and December 31, 2015, Fidelity had no outstanding derivative agreements. Fidelity historically utilized 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. The realized and unrealized gains and losses on the commodity derivative instruments, which were not designated as hedges, were both included in income (loss) from discontinued operations and the associated assets and liabilities were classified as held for sale.

16



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, 2016 and 2015, and December 31, 2015, 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,
 
2016
2015
 
(In thousands)
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
92

99

 
 
 
Commodity derivatives not designated as hedging instruments:
 
 
Amount of gain (loss) recognized in discontinued operations, before tax

(11,208
)
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.
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

 
 
(In thousands)
Not designated as hedges:
 
Commodity derivatives
Current assets held for sale
$
7,127

Total asset derivatives
 
$
7,127

 
 
 
 
 
All of the Company's commodity derivative instruments at March 31, 2015, 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

 
 
 
 
Note 12 - 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 $69.1 million, $67.8 million and $67.5 million, at March 31, 2016 and 2015, and December 31, 2015, respectively, are classified as Investments on the Consolidated Balance Sheets. The net unrealized gains on these investments were $1.6 million and $2.0 million for the three months ended March 31, 2016 and 2015, 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.

17



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, 2016
Cost

Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair Value

 
(In thousands)
Mortgage-backed securities
$
10,467

$
46

$
(14
)
$
10,499

Total
$
10,467

$
46

$
(14
)
$
10,499

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

December 31, 2015
Cost

Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair Value

 
(In thousands)
Mortgage-backed securities
$
9,128

$
19

$
(49
)
$
9,098

U.S. Treasury securities
1,315


(6
)
1,309

Total
$
10,443

$
19

$
(55
)
$
10,407

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 are valued at the net asset value of shares held at the end of the quarter, based on published market quotations on active markets, or using other known sources including pricing from outside sources.
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.
The estimated fair value of the Company's Level 2 RIN obligations are based on the market approach using quoted prices from an independent pricing service. RINs are assigned to biofuels produced or imported into the United States as required by the EPA, which sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the United States. As a producer of diesel fuel, Dakota Prairie Refinery is required to blend biofuels into the fuel it produces at a rate that will meet the EPA's quota. RINs are purchased in the open market to satisfy the requirement as Dakota Prairie Refinery is currently unable to blend biofuels into the diesel fuel it produces.
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, 2016 and 2015, there were no transfers between Levels 1 and 2.

18



The Company's assets and liabilities measured at fair value on a recurring basis were as follows:
 
Fair Value Measurements at March 31, 2016, 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, 2016

 
(In thousands)
Assets:
 
 
 
 
Money market funds
$

$
1,442

$

$
1,442

Insurance contract*

69,110


69,110

Available-for-sale securities:
 
 
 
 
Mortgage-backed securities

10,499


10,499

Total assets measured at fair value
$

$
81,051

$

$
81,051

Liabilities:
 
 
 
 
RIN obligations
$

$
4,951

$

$
4,951

Total liabilities measured at fair value
$

$
4,951

$

$
4,951

* The insurance contract invests approximately 9 percent in common stock of mid-cap companies, 6 percent in common stock of small-cap companies, 18 percent in common stock of large-cap companies, 65 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents.
 
 
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
$

$
1,087

$

$
1,087

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

Total assets measured at fair value
$

$
79,058

$

$
79,058

* 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.
 

19



 
Fair Value Measurements at December 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 December 31, 2015

 
(In thousands)
Assets:
 
 
 
 
Money market funds
$

$
1,420

$

$
1,420

Insurance contract*

67,459


67,459

Available-for-sale securities:
 
 
 
 
Mortgage-backed securities

9,098


9,098

U.S. Treasury securities

1,309


1,309

Total assets measured at fair value
$

$
79,286

$

$
79,286

Liabilities:
 
 
 
 
RIN obligations
$

$
3,052

$

$
3,052

Total liabilities measured at fair value
$

$
3,052

$

$
3,052

* The insurance contract invests approximately 9 percent in common stock of mid-cap companies, 7 percent in common stock of small-cap companies, 19 percent in common stock of large-cap companies, 63 percent in fixed-income investments, 1 percent in target date investments and 1 percent in cash equivalents.
 
The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including long-lived asset impairments. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company reviews the carrying value of its long-lived assets, excluding goodwill, whenever events or changes in circumstances indicate that such carrying amounts may not be recoverable.
The Company performed a fair value assessment of the assets and liabilities classified as held for sale. For more information on this Level 3 nonrecurring fair value measurement, see Note 9.
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, 2016
$
1,927,054

$
1,996,415

Long-term debt at March 31, 2015
$
2,183,644

$
2,334,339

Long-term debt at December 31, 2015
$
1,865,163

$
1,887,373

The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.
Note 13 - Equity
A summary of the changes in equity was as follows:
Three Months Ended March 31, 2016
Total Stockholders' Equity

Noncontrolling Interest

Total
Equity

 
(In thousands)
Balance at December 31, 2015
$
2,396,505

$
124,043

$
2,520,548

Net income (loss)
24,869

(11,040
)
13,829

Other comprehensive loss
(1,434
)

(1,434
)
Dividends declared on preferred stocks
(171
)

(171
)
Dividends declared on common stock
(36,620
)

(36,620
)
Stock-based compensation
1,065


1,065

Issuance of common stock upon vesting of stock-based compensation, net of shares used for tax withholdings
(316
)

(316
)
Net tax deficit on stock-based compensation
(1,517
)

(1,517
)
Balance at March 31, 2016
$
2,382,381

$
113,003

$
2,495,384


20



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

Note 14 - 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 midstream segment provides natural gas transportation, underground storage, gathering and processing 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.
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 other supplies.
The refining segment refines crude oil and produces and sells diesel fuel, naphtha, ATBs and other by-products of the production process. The refining segment includes Dakota Prairie Refinery which is jointly owned by WBI Energy and Calumet and is located in southwestern North Dakota, along with WBI Energy's other activity that supports the refinery.
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 includes certain general and administrative costs (reflected in operation and maintenance expense) and interest expense which were previously allocated to Fidelity and do not meet the criteria for income (loss) from discontinued operations. The Other category also includes Centennial Resources' former investment in the Brazilian Transmission Lines.
Discontinued operations includes the results of Fidelity other than certain general and administrative costs and interest expense as described above. Fidelity engaged in oil and natural gas development and production activities in the Rocky Mountain and Mid-Continent/Gulf States regions of the United States. Between September 2015 and March 2016, the Company entered into purchase and sale agreements to sell all of Fidelity's marketed oil and natural gas assets. The completion of these sales occurred between October 2015 and April 2016. For more information on discontinued operations, see Note 9.

21



The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the 2015 Annual Report. Information on the Company's businesses was as follows:
 
Three Months Ended
 
March 31,
 
2016

2015

 
(In thousands)
External operating revenues:
 
 
Regulated operations:
 
 
Electric
$
82,923

$
71,776

Natural gas distribution
299,395

330,573

Pipeline and midstream
3,420

3,940

 
385,738

406,289

Nonregulated operations:
 
 
Pipeline and midstream
8,697

13,000

Construction materials and contracting
209,852

205,658

Construction services
255,500

235,403

Refining
45,066

1,704

Other
300

295

 
519,415

456,060

Total external operating revenues
$
905,153

$
862,349

 
 
 
Intersegment operating revenues:
 

 

Regulated operations:
 
 
Electric
$

$

Natural gas distribution


Pipeline and midstream
21,225

21,261

 
21,225

21,261

Nonregulated operations:
 
 
Pipeline and midstream
84

325

Construction materials and contracting
118

948

Construction services
462

11,695

Refining


Other
1,669

1,772

 
2,333

14,740

Intersegment eliminations
(23,558
)
(36,001
)
Total intersegment operating revenues
$

$

 
 
 
Earnings (loss) on common stock:
 

 

Regulated operations:
 
 
Electric
$
11,119

$
8,328

Natural gas distribution
25,241

21,450

Pipeline and midstream
5,288

5,357

 
41,648

35,135

Nonregulated operations:
 
 
Pipeline and midstream
1

1,055

Construction materials and contracting
(14,471
)
(14,635
)
Construction services
5,974

4,760

Refining
(7,187
)
(2,394
)
Other
(550
)
(4,413
)
 
(16,233
)
(15,627
)
Intersegment eliminations
118

(991
)
Earnings on common stock before loss from
discontinued operations
25,533

18,517

Loss from discontinued operations, net of tax
(835
)
(324,605
)
Total earnings (loss) on common stock
$
24,698

$
(306,088
)

22



Note 15 - 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:
 
Pension Benefits
Other
Postretirement Benefits
Three Months Ended March 31,
2016

2015

2016

2015

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

$
40

$
450

$
483

Interest cost
4,390

4,364

949

914

Expected return on assets
(5,280
)
(5,373
)
(1,149
)
(1,175
)
Amortization of prior service cost (credit)

18

(343
)
(342
)
Amortization of net actuarial loss
1,593

1,735

448

461

Net periodic benefit cost, including amount capitalized
703

784

355

341

Less amount capitalized
81

76

34

29

Net periodic benefit cost
$
622

$
708

$
321

$
312

 
 
 
 
 
Prior to 2013, defined pension plan benefits and accruals for all nonunion and certain union plans were frozen. On June 30, 2015, an additional union plan was frozen. At December 31, 2015, all of the Company's defined pension plans were frozen. These employees were eligible to receive additional defined contribution plan benefits.
Nonqualified benefit plans
In addition to the qualified plan defined pension benefits reflected in the table, the Company also 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. In February 2016, the Company froze the unfunded, nonqualified defined benefit plans to new participants and eliminated upgrades. Vesting for participants not fully vested was retained. The Company's net periodic benefit credit for these plans for the three months ended March 31, 2016, was $1.9 million, which reflects a curtailment gain of $3.3 million. The Company's net periodic benefit cost for these plans for the three months ended March 31, 2015, was $1.7 million.
Multiemployer plans
On September 24, 2014, JTL - Wyoming 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 JTL - Wyoming's withdrawal liability. For the three months ended March 31, 2015, the Company accrued an additional withdrawal liability of approximately $2.4 million. The cumulative withdrawal liability is currently estimated at $16.4 million which has been accrued on the Consolidated Balance Sheets. The assessed withdrawal liability for this plan may be significantly different from the current estimate. Also, this plan's administrator has alleged that JTL - Wyoming owes additional contributions for periods of time prior to its withdrawal, which could affect its final assessed withdrawal liability. JTL - Wyoming disputes the plan administrator's demand for additional contributions, and on February 23, 2016, filed a declaratory judgment action in the United States District Court for the District of Wyoming to resolve the dispute.
Note 16 - Regulatory matters
On June 25, 2015, Montana-Dakota filed an application for an electric rate increase with the MTPSC. Montana-Dakota requested a total increase of approximately $11.8 million annually or approximately 21.1 percent above current rates to recover Montana-Dakota’s investments in modifications to generation facilities to comply with new EPA requirements, the addition and/or replacement of capacity and energy requirements and transmission facilities along with the additional depreciation, operation and maintenance expenses and taxes associated with the increases in investment. Montana-Dakota requested an interim increase of approximately $11.0 million annually. The MTPSC denied the request for interim rates on December 15, 2015. On February 8, 2016, Montana-Dakota and the interveners to the case filed a stipulation and settlement agreement reflecting an annual increase of $3.0 million effective April 1, 2016, and an additional increase of $4.4 million effective April 1, 2017. A technical hearing was held February 9, 2016. The MTPSC issued an order approving the settlement agreement on March 25, 2016. The approved rates were effective with service rendered on or after April 1, 2016.
On June 30, 2015, Montana-Dakota filed an application with the SDPUC for an electric rate increase. Montana-Dakota requested a total increase of approximately $2.7 million annually or approximately 19.2 percent above current rates to recover Montana-Dakota’s investments in modifications to generation facilities to comply with new EPA requirements, the addition and/or replacement of capacity and energy requirements and transmission facilities along with the additional depreciation, operation and

23



maintenance expenses and taxes associated with the increases in investment. This matter is pending before the SDPUC. An interim increase of $2.7 million, subject to refund, was implemented January 1, 2016. Montana-Dakota and the SDPUC staff have reached a settlement with the stipulations being finalized. A settlement hearing is scheduled for June 7, 2016.
On June 30, 2015, Montana-Dakota filed an application for a natural gas rate increase with the SDPUC. Montana-Dakota requested a total increase of approximately $1.5 million annually or approximately 3.1 percent above current rates to recover increased operating expenses along with increased investment in facilities, including the related depreciation expense and taxes, partially offset by an increase in customers and throughput. This matter is pending before the SDPUC. An interim increase of $1.5 million, subject to refund, was implemented January 1, 2016. Montana-Dakota and the SDPUC staff have reached a settlement with the stipulations being finalized. A settlement hearing is scheduled for June 7, 2016.
On September 30, 2015, Great Plains filed an application for a natural gas rate increase with the MNPUC. Great Plains requested a total increase of approximately $1.6 million annually or approximately 6.4 percent above current rates to recover increased operating expenses along with increased investment in facilities, including the related depreciation expense and taxes. Great Plains requested an interim increase of $1.5 million or approximately 6.4 percent, subject to refund. The interim request was approved by the MNPUC on November 30, 2015, and was effective with service rendered on and after January 1, 2016. This matter is pending before the MNPUC. A technical hearing was held April 7, 2016.
On October 21, 2015, Montana-Dakota filed an application with the NDPSC for an update of an electric generation resource recovery rider and requested a renewable resource cost adjustment rider. Montana-Dakota requested a combined total of approximately $25.3 million with approximately $20.0 million incremental to current rates, to be effective January 1, 2016. This application was resubmitted as two applications on October 26, 2015.
On October 26, 2015, Montana-Dakota filed an application requesting a renewable resource cost adjustment rider of $15.4 million for the recovery of the Thunder Spirit Wind project, placed in service in the fourth quarter of 2015. A settlement was reached with the NDPSC Advocacy Staff whereby Montana-Dakota agreed to a 10.5 percent return on equity on the renewable resource cost adjustment rider, as well as committed to file an electric general rate case no later than September 30, 2016. The renewable resource cost adjustment rider was approved by the NDPSC on January 5, 2016, to be effective January 7, 2016, resulting in an annual increase of $15.1 million on an interim basis pending the determination of the return on equity in the upcoming rate case.
On October 26, 2015, Montana-Dakota filed an application for an update to the electric generation resource recovery rider, which currently includes recovery of Montana-Dakota's investment in the 88-MW simple-cycle natural gas turbine and associated facilities near Mandan, North Dakota. The application proposed to also include the 19 MW of new generation from natural gas-fired internal combustion engines and associated facilities, near Sidney, Montana, placed in service in the fourth quarter of 2015, for a total of $9.9 million or an incremental increase of $4.6 million to be recovered under the rider. On January 25, 2016, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement which would result in an interim increase of $9.7 million or an incremental increase of $4.4 million, subject to refund, a 10.5 percent return on equity and Montana-Dakota would commit to filing an electric general rate case no later than September 30, 2016. A technical hearing on this matter was held on February 4, 2016. On March 9, 2016, the NDPSC issued an order approving the settlement agreement on an interim basis pending the determination in the upcoming rate case to be filed by September 30, 2016, on the return on equity and the net investment authorized for the natural gas-fired internal combustion engines located near Sidney, Montana. The interim rates were effective with service rendered on and after March 15, 2016.
On November 25, 2015, Montana-Dakota filed an application with the NDPSC for an update of its transmission cost adjustment for recovery of MISO-related charges and two transmission projects located in North Dakota, equating to $6.8 million to be collected under the transmission cost adjustment. An update to the transmission cost adjustment was submitted on January 19, 2016, to reflect the provisions of the settlement agreement approved by the NDPSC for the renewable resource cost adjustment rider whereby Montana-Dakota agreed to a 10.5 percent return on equity for this rider as well as committed to file an electric general rate case no later than September 30, 2016. An informal hearing with the NDPSC was held January 20, 2016, regarding this matter. The NDPSC approved the filing on February 10, 2016, on an interim basis with rates to be effective February 12, 2016.
On December 1, 2015, Cascade filed an application with the WUTC for a natural gas rate increase. Cascade requested a total increase of approximately $10.5 million annually or approximately 4.2 percent above current rates. The requested increase includes costs associated with increased infrastructure investment and the associated operating expenses. A settlement in principle has been accepted by all parties and is expected to be filed with the WUTC by the end of May 2016.
On April 29, 2016, Cascade filed an application with the OPUC for a natural gas rate increase of approximately $1.9 million annually or approximately 2.8 percent above current rates. The request includes costs associated with pipeline replacement and improvement projects to ensure the integrity of Cascade's system. This matter is pending before the OPUC.

24



Note 17 - 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 $19.0 million, $25.8 million and $19.5 million, which include liabilities held for sale, for contingencies, including litigation, production taxes, royalty claims and environmental matters at March 31, 2016 and 2015, and December 31, 2015, respectively, including amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note.
Litigation
Natural Gas Gathering Operations Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a gathering contract with Omimex as a result of the increased operating pressures demanded by a third party on a natural gas gathering system in Montana. 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.
Construction Materials Until the fall of 2011 when it discontinued active mining operations at the pit, JTL - Montana 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 - Montana was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL - Montana 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 - Montana 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. JTL - Montana filed an application for amendment of its opencut mining permit which it expects will be approved by the Montana DEQ in the first half of 2016. JTL - Montana intends to resolve this matter through settlement.
Construction Services Bombard Mechanical is a third-party defendant in litigation pending in Nevada State District Court in which the plaintiff, Palms Place, LLC, 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 presented cost of repair estimates totaling approximately $21 million for alleged plumbing and mechanical system defects associated in whole or in part with work performed by Bombard Mechanical. 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.
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

25



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 matter.
Coos County The Oregon DEQ issued a Notice of Civil Penalty to LTM dated October 12, 2015, asserting violations of Oregon water quality statutes and rules resulting from the stockpiling and grading of earthen material during 2014 at a site in Coos County and assessing civil penalties totaling approximately $160,000. The Notice of Civil Penalty alleges violations by causing pollution to an intermittent creek, by conducting activity described in a general National Pollutant Discharge Elimination System permit without applying for coverage under the general permit, by placing the earthen materials in a location where they were likely to escape or be carried into waters of the state, and by failing to submit a revised ESCP where there was a change in the size of the project or the location of the disturbed area. The Notice of Civil Penalty also requires LTM to submit a revised ESCP containing measures to prevent further erosion from entering the intermittent creek and to file a work plan outlining how the earthen material will be permanently stabilized or removed. LTM requested a contested case hearing on the Notice of Civil Penalty and is engaged in settlement negotiations with the Oregon DEQ. LTM intends to resolve the matter through settlement.
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, December 1, 2014 and December 1, 2015.
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. The 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 DOE 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 $12.9 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. The WUTC approved the petition in September 2010, subject to conditions set forth in the order.
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 DOE 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

26



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 2009, multiple sales agreements were signed to sell the Company's ownership interests in the Brazilian Transmission Lines. In connection with the sale, 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.

In March 2016, a sale agreement was signed to sell Fidelity's assets in the Paradox Basin. In connection with the sale, Centennial has agreed to guarantee Fidelity's indemnity obligations associated with the Paradox assets. The guarantee was required by the buyer as a condition to the sale of the Paradox Basin assets.

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, insurance deductibles and loss limits, and certain other guarantees. At March 31, 2016, the fixed maximum amounts guaranteed under these agreements aggregated $126.0 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $27.4 million in 2016; $34.1 million in 2017; $6.1 million in 2018; $54.4 million in 2019; and $4.0 million, which has no scheduled maturity date. There were no amounts outstanding under the above guarantees at March 31, 2016. 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, 2016, the fixed maximum amounts guaranteed under these letters of credit aggregated $56.1 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these letters of credit aggregate $27.9 million in 2016 and $28.2 million in 2017. The amount outstanding by subsidiaries of the Company under the above letters of credit was $500,000 and was reflected on the Consolidated Balance Sheet at March 31, 2016. 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.
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, 2016.
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, 2016, approximately $827.1 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 for construction in excess of $300 million were shared equally between WBI Energy and Calumet. WBI Energy's and Calumet's cumulative capital contributions, net of distributions, as of March 31, 2016, are $230.4 million and $163.6 million, respectively. Dakota Prairie Refining entered into a term loan for project debt financing of

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$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. The net loss attributable to noncontrolling interest on the Consolidated Statements of Income is pretax as Dakota Prairie Refining is a limited liability company. Given the current market conditions, challenges could include continued operating losses and the inability to fund operations. The Company is assessing strategic alternatives with respect to its ownership interest in Dakota Prairie Refining, is assessing the potential for a future impairment charge if current market conditions persist, and continues to assess potential impairment indicators.
Dakota Prairie Refining has an amended $75.0 million revolving credit agreement with a termination date of June 30, 2016. Pursuant to the revolving credit agreement, Centennial has issued a letter of credit supporting 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 may borrow up to $25.0 million at a variable interest rate from WBI Energy through June 30, 2016. Dakota Prairie Refining had $1.7 million of such borrowings outstanding at March 31, 2016. These borrowings are subordinate to the Dakota Prairie Refining revolving credit agreement. The amount outstanding was not reflected on the Consolidated Balance Sheet at March 31, 2016, because this intercompany transaction was eliminated in consolidation.
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 commenced operations in 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:
 
March 31, 2016

March 31, 2015

December 31, 2015

 
(In thousands)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
478

$
10,784

$
851

Accounts receivable
11,169

2,335

7,693

Inventories
17,056

7,902

13,176

Prepayments and other current assets
6,124

2,926

6,215

Total current assets
34,827

23,947

27,935

Net property, plant and equipment
419,492

425,944

425,123

Deferred charges and other assets:
 
 
 
Other
8,941

4,562

9,626

Total deferred charges and other assets
8,941

4,562

9,626

Total assets
$
463,260

$
454,453

$
462,684

Liabilities
 
 
 
Current liabilities:
 
 
 
Short-term borrowings
$
63,200

$
16,100

$
45,500

Long-term debt due within one year
6,375

3,000

5,250

Accounts payable
27,697

23,654

24,766

Taxes payable
1,001

569

1,391

Accrued compensation
717

683

938

Other accrued liabilities
7,155

1,016

4,953

Total current liabilities
106,145

45,022

82,798

Long-term debt
62,625

69,000

63,750

Total liabilities
$
168,770

$
114,022

$
146,548

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.

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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, 2016, 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, 2016, was $43.1 million.

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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 businesses, see Note 14.
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 is 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 Midstream
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, and investments in and acquisitions of energy-related assets and companies both in its current operating areas and beyond its northern Rockies base. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing storage, g