Attached files

file filename
EX-95 - EX-95 - Tri-State Generation & Transmission Association, Inc.tris-20150630xex95.htm
EX-32.1 - EX-32.1 - Tri-State Generation & Transmission Association, Inc.tris-20150630ex321e27f88.htm
EX-32.2 - EX-32.2 - Tri-State Generation & Transmission Association, Inc.tris-20150630ex322ce581f.htm
EX-31.2 - EX-31.2 - Tri-State Generation & Transmission Association, Inc.tris-20150630ex312b5ac72.htm
EX-31.1 - EX-31.1 - Tri-State Generation & Transmission Association, Inc.tris-20150630ex311cd9294.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


 

FORM 10-Q

 

(Mark One)

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

 

For the quarterly period ended June 30, 2015

 

OR

 

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

 

For the transition period from                      to

 

Commission File No. 333-203560

 

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Colorado

84-0464189

(State or other jurisdiction of incorporation or
organization)

(I.R.S employer identification
number)

 

 

1100 West 116th Ave,

 

Westminster, Colorado 80234

80234

(Address of principal executive offices)

(Zip Code)

 

(303) 452-6111

(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     No 

 

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes     No 

 

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 definitions of ‘‘large accelerated filer,’’ ‘‘accelerated filer,’’ and ‘‘smaller reporting company’’ in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer     Accelerated Filer     Non-Accelerated Filer     (Do not check if a smaller reporting company)  Smaller Reporting Company 

 

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

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.  The registrant is a membership corporation and has no authorized or outstanding equity securities.

 

 

 


 

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2015

 

 

 

 

 

    

Page Number

PART I.  FINANCIAL INFORMATION 

 

Item 1. 

Financial Statements

 

 

Consolidated Statements of Financial Position as of June 30, 2015 (unaudited) and December 31, 2014

 

Consolidated Statements of Operations - Three and Six Months Ended June 30, 2015 and 2014 (unaudited)

 

Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2015 and 2014 (unaudited)

 

Consolidated Statements of Equity - Six Months Ended June 30, 2015 and 2014 (unaudited)

 

Consolidated Statements of Cash Flows - Six Months Ended June 30, 2015 and 2014 (unaudited)

 

Notes to Unaudited Consolidated Financial Statements For the Three and Six Months Ended June 30, 2015 and 2014

614

Item 2. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

1524

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

25 

Item 4. 

Controls and Procedures

25 

PART II.  OTHER INFORMATION 

 

Item 1. 

Legal Proceedings

26 

Item 4. 

Mine Safety Disclosures

26 

Item 6. 

Exhibits

26 

SIGNATURES 

 

 

 

 

 

 

 

i


 

 

FORWARD-LOOKING STATEMENTS

 

This quarterly report on Form 10-Q contains ‘‘forward-looking statements.’’ All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as ‘‘will likely result,’’ ‘‘are expected to,’’ ‘‘will continue,’’ ‘‘is anticipated,’’ ‘‘estimated,’’ ‘‘projection,’’ ‘‘target’’ and ‘‘outlook’’) are forward-looking statements.

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements.

 

 

 

ii


 

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

 

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Financial Position (unaudited)

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

June 30, 2015

 

December 31, 2014

 

ASSETS

 

 

 

 

 

 

 

Property, plant and equipment

 

 

 

 

 

 

 

Electric plant

 

 

 

 

 

 

 

In service

 

$

5,261,818

 

$

5,193,236

 

Construction work in progress

 

 

265,824

 

 

206,097

 

Total electric plant

 

 

5,527,642

 

 

5,399,333

 

Less allowances for depreciation and amortization

 

 

(2,184,194)

 

 

(2,129,173)

 

Net electric plant

 

 

3,343,448

 

 

3,270,160

 

Other plant

 

 

228,446

 

 

210,694

 

Accumulated depreciation and depletion

 

 

(66,139)

 

 

(58,117)

 

Net other plant

 

 

162,307

 

 

152,577

 

Total property, plant and equipment

 

 

3,505,755

 

 

3,422,737

 

Other assets and investments

 

 

 

 

 

 

 

Investments in other associations

 

 

118,710

 

 

117,976

 

Investments in and advances to coal mines

 

 

17,555

 

 

15,016

 

Restricted cash and investments

 

 

4,956

 

 

39,376

 

Intangible assets

 

 

29,296

 

 

32,958

 

Other noncurrent assets

 

 

12,932

 

 

12,531

 

Total other assets and investments

 

 

183,449

 

 

217,857

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

103,804

 

 

92,468

 

Restricted cash and investments

 

 

10,304

 

 

9,784

 

Deposits and advances

 

 

30,651

 

 

22,224

 

Accounts receivable—Members

 

 

99,450

 

 

105,723

 

Other accounts receivable

 

 

22,992

 

 

25,693

 

Coal inventory

 

 

62,600

 

 

40,673

 

Materials and supplies

 

 

82,907

 

 

80,069

 

Total current assets

 

 

412,708

 

 

376,634

 

Deferred charges

 

 

 

 

 

 

 

Regulatory assets

 

 

424,635

 

 

426,043

 

Prepayment—NRECA Retirement and Security Plan

 

 

51,905

 

 

54,665

 

Other

 

 

179,871

 

 

178,454

 

Total deferred charges

 

 

656,411

 

 

659,162

 

Total assets

 

$

4,758,323

 

$

4,676,390

 

EQUITY AND LIABILITIES

 

 

 

 

 

 

 

Capitalization

 

 

 

 

 

 

 

Patronage capital equity

 

$

935,079

 

$

908,669

 

Accumulated other comprehensive income (loss)

 

 

(834)

 

 

(828)

 

Noncontrolling interest

 

 

109,015

 

 

109,302

 

Total equity

 

 

1,043,260

 

 

1,017,143

 

Long-term debt

 

 

3,245,319

 

 

3,165,960

 

Total capitalization

 

 

4,288,579

 

 

4,183,103

 

Current liabilities

 

 

 

 

 

 

 

Member advances

 

 

12,594

 

 

14,576

 

Accounts payable

 

 

96,693

 

 

103,177

 

Accrued expenses

 

 

27,657

 

 

30,005

 

Accrued interest

 

 

34,179

 

 

32,517

 

Accrued property taxes

 

 

17,430

 

 

26,010

 

Current maturities of long-term debt

 

 

97,157

 

 

94,342

 

Total current liabilities

 

 

285,710

 

 

300,627

 

Deferred credits and other liabilities

 

 

 

 

 

 

 

Regulatory liabilities

 

 

45,000

 

 

45,000

 

Deferred income tax liability

 

 

27,625

 

 

17,230

 

Intangible liabilities

 

 

7,904

 

 

9,424

 

Asset retirement obligations

 

 

58,364

 

 

53,754

 

Other

 

 

36,768

 

 

59,121

 

Total deferred credits and other liabilities

 

 

175,661

 

 

184,529

 

Accumulated postretirement benefit and postemployment obligations

 

 

8,373

 

 

8,131

 

Total equity and liabilities

 

$

4,758,323

 

$

4,676,390

 

 

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

1


 

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Operations (unaudited)

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

 

    

2015

    

2014

    

2015

    

2014

 

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Member electric sales

 

$

257,292

 

$

256,274

 

$

524,831

 

$

520,868

 

Non-member electric sales

 

 

29,785

 

 

50,599

 

 

64,848

 

 

110,060

 

Other

 

 

18,836

 

 

20,415

 

 

44,625

 

 

45,558

 

 

 

 

305,913

 

 

327,288

 

 

634,304

 

 

676,486

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased power

 

 

71,284

 

 

73,498

 

 

144,421

 

 

152,427

 

Fuel

 

 

35,569

 

 

70,386

 

 

96,844

 

 

144,302

 

Production

 

 

70,377

 

 

61,165

 

 

123,897

 

 

114,178

 

Transmission

 

 

37,972

 

 

36,873

 

 

75,071

 

 

72,627

 

General and administrative

 

 

5,472

 

 

7,093

 

 

11,623

 

 

13,290

 

Depreciation and amortization

 

 

35,968

 

 

31,188

 

 

70,946

 

 

62,085

 

Coal mining

 

 

7,116

 

 

8,961

 

 

15,943

 

 

21,445

 

Other

 

 

3,605

 

 

4,026

 

 

7,625

 

 

8,382

 

 

 

 

267,363

 

 

293,190

 

 

546,370

 

 

588,736

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating margins

 

 

38,550

 

 

34,098

 

 

87,934

 

 

87,750

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Income

 

 

1,087

 

 

3,058

 

 

2,170

 

 

6,319

 

Capital credits from cooperatives

 

 

947

 

 

368

 

 

5,241

 

 

2,038

 

Other income

 

 

503

 

 

406

 

 

1,851

 

 

1,675

 

 

 

 

2,537

 

 

3,832

 

 

9,262

 

 

10,032

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net of amounts capitalized

 

 

34,910

 

 

34,889

 

 

71,073

 

 

70,631

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income taxes

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net margins including noncontrolling interest

 

 

6,177

 

 

3,041

 

 

26,123

 

 

27,151

 

Net loss attributable to noncontrolling interest

 

 

107

 

 

332

 

 

287

 

 

733

 

Net margins attributable to the Association

 

$

6,284

 

$

3,373

 

$

26,410

 

$

27,884

 

 

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

2


 

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Comprehensive Income (unaudited)

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 

 

Six Months Ended June 30, 

 

 

    

2015

    

2014

    

2015

    

2014

 

Net margins including noncontrolling interest

 

$

6,177

 

$

3,041

 

$

26,123

 

$

27,151

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized gain (loss) on securities available for sale

 

 

(7)

 

 

41

 

 

(23)

 

 

16

 

Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income

 

 

8

 

 

(86)

 

 

17

 

 

(179)

 

Income tax expense related to components of other comprehensive loss

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

Other comprehensive income (loss)

 

 

1

 

 

(45)

 

 

(6)

 

 

(163)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income including noncontrolling interest

 

 

6,178

 

 

2,996

 

 

26,117

 

 

26,988

 

Net comprehensive loss attributable to noncontrolling interest

 

 

107

 

 

332

 

 

287

 

 

733

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income attributable to the Association

 

$

6,285

 

$

3,328

 

$

26,404

 

$

27,721

 

 

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

3


 

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Equity (unaudited)

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended June 30, 

 

 

    

2015

    

2014

 

Patronage capital equity at beginning of period

 

$

908,669

 

$

865,379

 

 

 

 

 

 

 

 

 

Net margins attributable to the Association

 

 

26,410

 

 

27,884

 

Retirement of patronage capital

 

 

 —

 

 

(10,000)

 

Patronage capital equity at end of period

 

 

935,079

 

 

883,263

 

 

 

 

 

 

 

 

 

Accumulated other comprehensive income (loss) at beginning of period

 

 

(828)

 

 

3,335

 

 

 

 

 

 

 

 

 

Unrealized gain (loss) on securities available for sale

 

 

(23)

 

 

16

 

Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income

 

 

17

 

 

(179)

 

Accumulated other comprehensive income (loss) at end of period

 

 

(834)

 

 

3,172

 

 

 

 

 

 

 

 

 

Noncontrolling interest at beginning of period

 

 

109,302

 

 

110,740

 

 

 

 

 

 

 

 

 

Net loss attributable to noncontrolling interest

 

 

(287)

 

 

(733)

 

Equity distribution to noncontrolling interest

 

 

 —

 

 

 —

 

Noncontrolling interest at end of period

 

 

109,015

 

 

110,007

 

Total equity at end of period

 

$

1,043,260

 

$

996,442

 

 

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

4


 

 

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Cash Flows (unaudited)

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended June 30, 

 

 

  

2015

  

2014

 

Operating activities

 

 

 

 

 

 

 

Net margins including noncontrolling interest

 

$

26,123

 

$

27,151

 

Adjustments to reconcile net margins to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation and amortization

 

 

70,946

 

 

60,066

 

Amortization of intangible asset

 

 

3,662

 

 

3,662

 

Amortization of NRECA Retirement and Security Plan prepayment

 

 

2,760

 

 

2,760

 

Amortization of debt issuance costs

 

 

929

 

 

464

 

Capital credit allocations from cooperatives and income from coal mines under (over) refund distributions

 

 

(3,528)

 

 

105

 

Recognition of deferred revenue

 

 

 —

 

 

(10,000)

 

Change in restricted cash and investments

 

 

29,192

 

 

15,994

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

 

 

8,977

 

 

(328)

 

Coal inventory

 

 

(21,927)

 

 

14,719

 

Materials and supplies

 

 

(2,838)

 

 

(5,339)

 

Accounts payable and accrued expenses

 

 

(2,097)

 

 

(7,529)

 

Accrued interest

 

 

1,662

 

 

(1,420)

 

Accrued property taxes

 

 

(8,580)

 

 

(6,707)

 

Other deferred credits - BNSF settlement

 

 

(29,381)

 

 

 —

 

Other

 

 

1,374

 

 

(1,941)

 

Net cash provided by operating activities

 

 

77,274

 

 

91,657

 

 

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

 

 

Purchases of plant

 

 

(150,447)

 

 

(83,418)

 

Changes in deferred charges

 

 

2,474

 

 

(8,236)

 

Proceeds from other investments

 

 

399

 

 

1,857

 

Net cash used in investing activities

 

 

(147,574)

 

 

(89,797)

 

 

 

 

 

 

 

 

 

Financing activities

 

 

 

 

 

 

 

Member advances

 

 

(1,982)

 

 

2,088

 

Payments of long-term debt

 

 

(92,073)

 

 

(145,989)

 

Proceeds from issuance of debt

 

 

175,359

 

 

50,000

 

Decrease in advance payments to RUS

 

 

 —

 

 

30,865

 

Retirement of patronage capital

 

 

(4,213)

 

 

(13,849)

 

Change in restricted cash and investments

 

 

323

 

 

 —

 

Proceeds from investment in securities pledged as collateral

 

 

4,222

 

 

4,526

 

Net cash provided by (used in) financing activities

 

 

81,636

 

 

(72,359)

 

 

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

 

11,336

 

 

(70,499)

 

Cash and cash equivalents – beginning

 

 

92,468

 

 

193,057

 

Cash and cash equivalents – ending

 

$

103,804

 

$

122,558

 

 

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

 

 

Cash paid for interest

 

$

76,548

 

$

81,214

 

 

 

 

 

 

 

 

 

Supplemental disclosure of noncash investing and financing activities:

 

 

 

 

 

 

 

Change in plant expenditures included in accounts payable

 

$

(2,277)

 

$

4,770

 

 

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

5


 

Tri-State Generation and Transmission Association, Inc.

Notes to Unaudited Consolidated Financial Statements

For the Three and Six Months Ended June 30, 2015 and 2014

 

NOTE 1 – PRESENTATION OF FINANCIAL INFORMATION

 

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, they do not include all of the information and footnotes required by U.S. generally accepted accounting principles (“GAAP”) for complete financial statements.  These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our 2014 Annual Report in our Registration Statement on Form S-4 (Registration No. 333-203560) that was declared effective by the SEC on July 29, 2015.  In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included.  The results of operations for the three and six months ended June 30, 2015 and 2014 are not necessarily indicative of the results that may be expected for an entire year or any other period.

 

Basis of Consolidation

 

Our consolidated financial statements include the accounts of Tri-State Generation and Transmission Association, Inc., our wholly-owned and majority-owned subsidiaries and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries (see Note 10 – Variable Interest Entities).  Our consolidated financial statements also include our undivided interests in jointly owned facilities.  All significant intercompany balances and transactions have been eliminated in consolidation. 

 

Jointly Owned Facilities

 

We own undivided interests in three jointly owned generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common.  These projects include the Yampa Project (operated by us), the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“BEPC”)) and the San Juan Project (operated by Public Service Company of New Mexico).  Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership.  Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility.  The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility.  Therefore, our share of the plant asset cost, interest, depreciation and operating expenses is included in our consolidated financial statements.

 

Our share in each jointly owned facility is as follows as of June 30, 2015 (thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

  

 

  

Electric

  

 

 

  

Construction

 

 

 

Tri-State

 

Plant in

 

Accumulated

 

Work In

 

 

 

Share

 

Service

 

Depreciation

 

Progress

 

Yampa Project - Craig Station Units 1 and 2

 

 

24

%  

$

345,469

 

$

227,967

 

$

14,138

 

MBPP - Laramie River Station

 

 

24.13

%

 

388,218

 

 

290,284

 

 

11,108

 

San Juan Project – San Juan Unit 3

 

 

8.2

%  

 

73,501

 

 

56,405

 

 

10,333

 

Total

 

 

 

 

$

807,188

 

$

574,656

 

$

35,579

 

 

 

NOTE 2 – ACCOUNTING FOR RATE REGULATION:

 

We are subject to the accounting requirements related to regulated operations.  In accordance with these accounting requirements, some revenues and expenses have been deferred at the discretion of our Board of Directors, which has budgetary and rate-setting authority, if it is probable that these amounts will be refunded or recovered through future rates.  Regulatory assets are costs that we expect to recover from our Members through rates approved by our Board of

6


 

Directors in accordance with our rate policy.  Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Members based on rates approved by our Board of Directors in accordance with our rate policy.

 

Regulatory assets and liabilities are as follows (thousands):

 

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

 

  

2015

  

2014

 

Regulatory assets

 

 

 

 

 

 

 

Deferred income tax expense (1)

 

$

27,625

 

$

17,230

 

Deferred prepaid lease expense- Craig 3 Lease (2)

 

 

19,420

 

 

22,656

 

Deferred prepaid lease expense- Springerville 3 Lease (3)

 

 

94,023

 

 

95,168

 

Goodwill – J.M. Shafer (4)

 

 

61,965

 

 

63,390

 

Goodwill – Colowyo Coal (5)

 

 

41,843

 

 

43,526

 

Deferred debt prepayment transaction costs (6)

 

 

179,759

 

 

184,073

 

 

 

 

424,635

 

 

426,043

 

Regulatory liabilities

 

 

 

 

 

 

 

Deferred revenues (7)

 

 

45,000

 

 

45,000

 

Net regulatory asset

 

$

379,635

 

$

381,043

 

 

(1)

A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.

(2)

Deferral of loss on acquisition related to the Craig Generating Station Unit 3 prepaid lease expense upon acquisitions of equity interests in 2002 and 2006.  The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $6.5 million annually through the remaining original life of the lease ending in 2018 and recovered from our Members in rates.

(3)

Deferral of loss on acquisition related to the Springerville Generating Station Unit 3 prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009.  The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Members in rates.

(4)

Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011.  Goodwill is being amortized to depreciation and amortization expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Members in rates.

(5)

Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011.  Goodwill is being amortized to depreciation and amortization expense through the 44-year period ending in 2056 and recovered from our Members in rates.

(6)

Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014.  These costs are being amortized to depreciation and amortization expense in the amount of $8.6 million annually over the 21.4-year average life of the new debt issued and recovered from our Members in rates.

(7)

Represents deferral of the recognition of $10 million of non-member electric sales revenue received in 2008 and $35 million of non-member electric sales revenue received in 2011.  These deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods.

 

NOTE 3 – INVESTMENTS IN OTHER ASSOCIATIONS:  

 

Investments in other associations include our investment in the patronage capital of other cooperatives and these investments are typically accounted for using the cost method.  Under this method, our investment in a cooperative increases when a cooperative allocates patronage capital credits to us and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative.  Investments in cooperatives where we have significant influence over operating and financial policy are accounted for using the equity method.  A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. 

 

7


 

 

NOTE 4 – RESTRICTED CASH AND INVESTMENTS:    

 

Restricted cash and investments represent funds designated by our Board of Directors for specific uses and funds restricted by contract or other legal reasons.  A portion of the funds is for the payment of debt within one year and is therefore a current asset on the statements of financial position.  The other funds are noncurrent and are included in other assets and investments.  

 

We have investments in U.S. Treasury Notes pledged as collateral in connection with the in-substance defeasance for the principal outstanding and future interest payments on the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”).  The balances in these investments are described as investments in securities pledged as collateral in the table below.  A portion of the defeasance investment is for Colowyo Bond debt payments within one year and is, therefore, a current asset on the consolidated statements of financial position.  The remainder of the investment is noncurrent.  

 

We received $29.4 million in 2009 from the BNSF Railway Company (“BNSF”) as a reduction of prior coal delivery shipping charges as the result of the decision of the Surface Transportation Board (“STB”).  However, BNSF appealed the decision and the funds were subject to refund in the event BNSF was ultimately successful in its appeal.  These funds were designated by our Board of Directors to be held as restricted cash.  In May 2015, BNSF, Western Fuels Association (“WFA”) and BEPC filed a joint petition at the STB informing the STB that the parties had entered into a rail transportation agreement settling all matters at issue.  In June 2015, the STB granted the joint petition, which resolved the uncertainties related to the outcome of this matter and the $29.4 million of cash related to the BNSF settlement was no longer designated as restricted. 

 

Restricted cash and investments are as follows (thousands):

 

 

 

 

 

 

 

 

 

 

  

June 30, 

 

December 31, 

 

 

 

2015

  

2014

 

Investments in securities pledged as collateral

 

$

9,524

 

$

9,192

 

Funds restricted by contract

 

 

780

 

 

592

 

Restricted cash and investments - current

 

 

10,304

 

 

9,784

 

BNSF settlement

 

 

 —

 

 

29,381

 

Funds restricted by contract

 

 

1,000

 

 

1,000

 

Investments in securities pledged as collateral

 

 

3,956

 

 

8,995

 

Restricted cash and investments - noncurrent

 

 

4,956

 

 

39,376

 

Total restricted cash and investments

 

$

15,260

 

$

49,160

 

 

 

NOTE 5 – OTHER DEFERRED CHARGES:   

 

We make expenditures for preliminary surveys, plans and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects.  If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress.  If the work is abandoned, the related preliminary survey and investigation expenditures may be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Members in rates subject to approval by our Board of Directors, which has budgetary and rate-setting authority.  As of June 30, 2015, preliminary survey and investigation was primarily comprised of expenditures for the Holcomb Station Project of $84.2 million and $27.9 million for a transmission project located in eastern Colorado (“Eastern Plains Transmission Project”).

 

We make advance payments to the operating agents of jointly owned facilities. 

 

We account for debt issuance costs as deferred debt expense.  Deferred debt expense is amortized to expense using an effective interest method over the life of the respective debt issuance.  As of June 30, 2015, the remaining amortization periods for debt issuance costs range from approximately 2 to 34 years.

 

8


 

Other deferred charges are as follows (thousands):

 

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

 

    

2015

  

2014

 

Preliminary surveys, plans and investigation

 

$

135,292

 

$

131,693

 

Advances to operating agents of jointly owned facilities

 

 

18,093

 

 

20,567

 

Debt issuance costs

 

 

21,966

 

 

22,254

 

Other

 

 

4,520

 

 

3,940

 

Total other deferred charges

 

$

179,871

 

$

178,454

 

 

 

NOTE 6 – LONG-TERM DEBT

 

The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement except for one unsecured note.  Substantially all our assets, rents, revenues and margins are pledged as collateral.  The Springerville certificates are secured by the assets of Springerville Generating Station Unit 3.  The Colowyo Bonds are secured by funds deposited with the trustee as part of the in-substance defeasance and an unconditional guarantee by us.  All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement and an equity to capitalization ratio requirement. 

 

We have a secured revolving credit facility with Bank of America, N.A. and CoBank, ACB as Joint Lead Arrangers in the amount of $750 million (“2011 Credit Agreement”).  We had outstanding borrowings of $206 million and $50 million at June 30, 2015 and December 31, 2014, respectively, and an issued letter of credit in the principal amount of $46.8 million plus accrued interest supported by the 2011 Credit Agreement.  As of June 30, 2015, we have $496 million in availability under the 2011 Credit Agreement.

 

Long-term debt consists of the following (thousands):

 

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

 

    

2015

  

2014

 

Total debt

 

$

3,342,476

 

$

3,260,302

 

Less current maturities

 

 

(97,157)

 

 

(94,342)

 

Long-term debt

 

$

3,245,319

 

$

3,165,960

 

 

 

 

 

NOTE 7 – OTHER DEFERRED CREDITS AND OTHER LIABILITIES   

 

We received $29.4 million in 2009 from the BNSF as a reduction of prior coal delivery shipping charges as the result of the decision of the STB.  However, BNSF appealed the decision and the funds were subject to refund in the event BNSF was ultimately successful in its appeal.  Due to uncertainties regarding the ultimate outcome of this matter, we did not recognize the benefit of the receipt of the $29.4 million in 2009.  In May 2015, BNSF, WFA, and BEPC filed a joint petition at the STB informing the STB that the parties had entered into a rail transportation agreement settling all matters at issue.  In June 2015, the STB granted the joint petition, which resolved the uncertainties related to the outcome of this matter.  Therefore, pursuant to the BNSF rate settlement, $24.4 million was recognized in June 2015 as a reduction to fuel expense.

 

We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits.  We have received upfront payments from others for the use of optical fiber and these are reflected in unearned revenue until recognized over the life of the agreement.

 

9


 

Other deferred credits and other liabilities are as follows (thousands):

 

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

 

    

2015

  

2014

 

BNSF rate settlement proceeds not recognized in income

 

$

 —

 

$

29,381

 

Customer deposits

 

 

3,759

 

 

2,464

 

Unearned revenue

 

 

4,820

 

 

4,210

 

Other deferred credits

 

 

28,189

 

 

23,066

 

Total other deferred credits and other liabilities

 

$

36,768

 

$

59,121

 

 

 

 

NOTE 8 – INCOME TAXES

 

We are a taxable cooperative subject to federal and state taxation.  As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital.  We utilize the liability method of accounting for income taxes.  Accordingly, changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability.  A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.  We had no income tax expense or benefit for the three and six months ended June 30, 2015 and 2014.

 

NOTE 9 – FAIR VALUE

 

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal or in the most advantageous market when no principal market exists.  The fair value measurements accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement.  Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress).  In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows:

 

Level 1 inputs utilize observable market data in active markets for identical assets or liabilities.

 

Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

 

Level 3 inputs consist of unobservable market data which are typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity.

 

In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety.  The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

 

Marketable Securities

 

We hold marketable securities in connection with the directors’ and executives elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds.  These securities are classified as available-for-sale and are measured at fair value on a recurring basis.  The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position.  The unrealized gains are reported as a component of accumulated other comprehensive income.  Changes in the net unrealized gains or losses are

10


 

reported as a component of comprehensive income.  The carrying amounts and fair values of our marketable securities are as follows (thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of June 30, 2015

 

As of December 31, 2014

 

 

 

 

Carrying

 

 

Estimated

 

 

Carrying

 

 

Estimated

 

 

  

 

Amount

  

 

Fair Value

  

 

Amount

  

 

Fair Value

 

Marketable securities

  

$

947

  

$

1,178

  

$

1,095

  

$

1,349

 

 

The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position.  The unrealized gains at June 30, 2015 and December 31, 2014 are reported as a component of accumulated other comprehensive income as of those dates.  Changes in the net unrealized gains or losses are reported as a component of comprehensive income.

 

Long-Term Debt

 

The fair values of long-term debt were estimated using discounted cash flow analyses based on our current incremental borrowings rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs).

 

The carrying amounts and fair values of our long-term debt are as follows (thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of June 30, 2015

 

As of December 31, 2014

 

 

 

 

Carrying

 

 

Estimated

 

 

Carrying

 

 

Estimated

 

 

  

 

Amount

  

 

Fair Value

  

 

Amount

  

 

Fair Value

 

Long-term debt

 

$

3,342,476

 

$

3,607,269

 

$

3,260,302

 

$

3,716,513

 

 

We did not have any financial assets or liabilities measured at fair value on a recurring basis that are included in the Level 3 fair value category.

 

NOTE 10 – VARIABLE INTEREST ENTITIES

 

The following is a description of our financial interests in variable interest entities that we consider significant.  This includes an entity for which we are determined to be the primary beneficiary and therefore consolidate and also entities for which we are not the primary beneficiary and therefore do not consolidate. 

 

Consolidated Variable Interest Entity:

 

Springerville Partnership:    We own a 51 percent equity interest, including the 1 percent general partner equity interest in the Springerville Partnership, which is the 100 percent owner of Springerville Unit 3 Holding LLC (“Owner Lessor”) of the Springerville Generating Station Unit 3.  We, as general partner, have the full exclusive and complete right, power and discretion to operate, manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville Partnership in good standing without the consent of the limited partners.  Additionally, the Owner Lessor has historically not demonstrated an ability to finance its activities without additional financial support.  The financial support is provided by our remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Generating Station Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership.  We have the primary risk (expense) exposure in operating the Springerville Generating Station Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Generating Station Unit 3 and the decisions related to those expenditures including budgeting, financing and dispatch of power.  Based on all these facts, it was determined that we are the primary beneficiary of the Owner Lessor.  Therefore, the Springerville Partnership and Owner Lessor have been consolidated by us.  

 

Our consolidated statements of financial position include the Springerville Partnership’s net electric plant of $863.8 and $874.4 million at June 30, 2015 and December 31, 2014, respectively, the long-term debt of $512.1 and $548.1 million

11


 

at June 30, 2015 and December 31, 2014, respectively, accrued interest associated with the long-term debt of $14.3 million and $15.2 million at June 30, 2015 and December 31, 2014, respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $109.0 and $109.3 million at June 30, 2015 and December 31, 2014, respectively.

 

Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $5.3 million for the three months ended June 30, 2015 and the comparable period in 2014.  Our consolidated statements of operations also include interest expense of $8.0 million for the three months ended June 30, 2015 and $8.5 million for the comparable period in 2014.  Our consolidated statements of  operations include the Springerville Partnership’s depreciation and amortization expense of $10.5 million for the six months ended June 30, 2015 and the comparable period in 2014.  Our consolidated statements of operations also include interest expense of $16.2 million for the six months ended June 30, 2015 and $17.1 million for the comparable period in 2014.  The net losses attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership are reflected on our consolidated statements of operations.  The revenue associated with the Springerville Partnership lease has been eliminated in consolidation.  Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages.

 

Unconsolidated Variable Interest Entities:  

 

Western Fuels Association (“WFA”):  WFA is a not-for-profit membership corporation organized for the purpose of acquiring and supplying fuel resources to its members, which includes us.  WFA supplies fuel to MBPP for the use of the Laramie River Station through its ownership in Western Fuels-Wyoming.  We also receive coal supplies directly from WFA for the Escalante Generating Station in New Mexico and spot coal for the Springerville Generating Station Unit 3 in Arizona.  The pricing structure of the coal supply agreements with WFA is designed to recover the mine operating costs of the mine supplying the coal and therefore the coal sales agreements provide the financial support for the mine operations.  There isn’t sufficient equity at risk for WFA to finance its activities without additional financial support.  Therefore, WFA is considered a variable interest entity in which we have a variable interest.  The power to direct the activities that most significantly impact WFA’s economic performance (acquiring and supplying fuel resources) is held by the members who are represented on the WFA board of directors whose actions require joint approval.  Therefore, since there is shared power over the significant activities of WFA, we are not the primary beneficiary of WFA and the entity is not consolidated.  Our investment in WFA, accounted for using the cost method, was $2.3 million at June 30, 2015 and December 31, 2014, respectively and is included in investments in other associations.

 

Western Fuels – Wyoming (“WFW”):  WFW, the owner and operator of the Dry Fork Mine in Gillette, WY, was organized for the purpose of acquiring and supplying coal, through long-term coal supply agreements, to be used in the production of electric energy at the Laramie River Station (owned by the participants of MBPP) and at the Dry Fork Station (owned by BEPC).  WFA owns 100 percent of the class AA shares and 75 percent of the class BB shares of WFW, while the participants of MBPP (of which we have a 24.1 percent undivided interest) own the remaining 25 percent of class BB shares of WFW.  The pricing structure of the coal supply agreements is designed to recover the costs of production of the Dry Fork Mine and therefore the coal supply agreements provide the financial support for the operation of the Dry Fork Mine.  There isn’t sufficient equity at risk at WFW for it to finance its activities without additional financial support.  Therefore, WFW is considered a variable interest entity in which we have a variable interest.  The power to direct the activities that most significantly impact WFW’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the equity interest holders since each member has representation on the WFW board of directors whose actions require joint approval.  Therefore, we are not the primary beneficiary of WFW and the entity is not consolidated. 

 

Trapper Mining, Inc. (“Trapper Mining”):  Trapper Mining is a cooperative organized for the purpose of mining, selling and delivering coal from the Trapper Mine to the Craig Generating Station Units 1 and 2 through long-term coal supply agreements.  Trapper Mining is jointly owned by some of the participants of the Yampa Project (the owners of the Craig Generating Station Units 1 and 2).  We have a 26.57 percent cooperative member interest in Trapper Mining.  The pricing structure of the coal supply agreements is designed to recover the costs of production of the Trapper Mine and therefore the coal supply agreements provide the financial support for the operation of the Trapper Mine.  There isn’t sufficient equity at risk for Trapper Mining to finance its activities without the additional financial support.  Therefore,

12


 

Trapper Mining is considered a variable interest entity in which we have a variable interest.  The power to direct the activities that most significantly impact Trapper Mining’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the cooperative members since each member has representation on the Trapper Mining board of directors whose actions require joint approval.  Therefore, we are not the primary beneficiary of Trapper Mining and the entity is not consolidated.  We record our investment in Trapper Mining using the equity method.  Our membership interest in Trapper Mining was $15.7 million at June 30, 2015 and $13.7 million at December 31, 2014.

 

NOTE 11 – LEGAL

 

On February 9, 2015, Delta-Montrose Electric Association (‘‘DMEA’’) filed a Petition For Declaratory Order with the United States Federal Energy Regulatory Commission (‘‘FERC’’) seeking a declaratory order from FERC finding that its wholesale electric service contract with us is subject to FERC jurisdiction because we have paid off all our Rural Utilities Service debt; that the wholesale electric service contract cannot be read to preclude DMEA from purchasing power from a ‘‘qualifying facility,’’ which is a co-generator or renewable small power producer capable of producing up to 80 MW, pursuant to the provisions of PURPA and FERC regulations thereunder; and that DMEA has the right under FERC’s PURPA regulations to negotiate its purchase power price from a ‘‘qualifying facility’’ and to reduce its purchases from us by that amount even if that amount exceeds its contractual obligation to purchase from us. We filed our motion to intervene and protest with FERC related to such petition on March 11, 2015. DMEA filed a motion to answer and answer to our protest on March 26, 2015. We filed a motion for leave to answer and answer to DMEA’s answer on April 2, 2015. On June 18, 2015, FERC issued an order stating (a) DMEA is obligated to purchase from “qualifying facilities” offering available energy and capacity and such sales may be at negotiated rates and (b) we are not subject to the general FERC rate jurisdiction under the Federal Powers Act (“FPA”).  On July 20, 2015, Kit Carson Electric Cooperative, Inc. (“Kit Carson”) filed a Motion for Clarification or Alternatively, Rehearing with FERC seeking a clarification of the FERC order, or alternatively, a rehearing, to the extent the FERC order applies to any of our policies or the application of any of our policies regarding Kit Carson’s obligations under PURPA to purchase renewable energy from a “qualifying facility” and as it relates to Kit Carson’s obligation to purchase and receive at least 95 percent of its electric power requirements from us under the wholesale electric service contract.  On August 3, 2015, we filed a motion for leave to answer and answer to Kit Carson’s motion requesting FERC to deny Kit Carson’s motion because it is beyond the scope of FERC’s order in the proceeding and not within FERC’s jurisdiction under the FPA.  We do not expect the FERC order or the outcome related to Kit Carson’s motion to have a material adverse effect on our financial condition or our future results of operations or cash flows.  We are evaluating our options regarding its impact on our wholesale electric service contracts with our Members.

 

In February 2013, WildEarth Guardians (‘‘WEG’’) filed suit against the United States Office of Surface Mining, Reclamation and Enforcement (‘‘OSM’’), in the United States District Court for the District of Colorado, alleging OSM’s failure to involve the public and address the economic impacts of coal mining throughout the Rocky Mountain West prior to mine plan approval. The suit alleged unlawful mine plan approval of mines located in Colorado, Montana, New Mexico, and Wyoming. The court granted intervention to several mine owners, including Colowyo Coal and Trapper Mining. The Colowyo Mine plan in WEG’s suit was approved in 2007 and the Trapper Mine plan in WEG’s suit was approved in 2009. In February 2014, the court agreed to sever the claims and transfer venue for the mines located outside of Colorado. In August 2014, WEG submitted its opening brief on the part of the case that remained in Colorado as Civil Action No. 1:13-cv-00518-RBJ. OSM’s responsive brief was filed on October 7, 2014, and Trapper Mining and Colowyo Coal, as intervenors, each filed a responsive brief on October 20, 2014. WEG has asked the court to declare that OSM’s approval of the mine plans violated the National Environmental Policy Act (‘‘NEPA’’) and for the court to vacate the approvals until OSM demonstrates compliance with the act. Oral arguments took place on April 24, 2015. On May 8, 2015, the court issued an order agreeing with WEG that OSM’s approval of the mine plans violated NEPA. The court noted that the majority of the coal covered by the permit at Trapper Mine had already been mined, but ordered that no remaining coal covered by the permit be mined prior to approval of a new permit revision. With respect to the Colowyo Mine, the court determined that immediate vacatur of the Colowyo Mine plan did not outweigh the potential harm. The court deferred an immediate vacatur order for a period of 120 days from May 8, 2015 and expected the OSM during that time to address the deficiencies in the permitting process. Colowyo Coal is working with OSM to respond to the court’s order within the 120 days and OSM has undertaken efforts to respond to the court’s order within the 120 days. On May 29, 2015, Colowyo Coal filed a Notice of Appeal and Motion to Stay the Order issued by the court. In the

13


 

event the OSM does not respond to the court’s order within the 120 days and the court enters a vacatur order, we are evaluating our options as to alternatives. On July 25, 2015, the court denied Colowyo Coal’s Motion to Stay the Order.  On July 27, 2015, OSM released a draft remedial environmental assessment of Colowyo Coal’s mining permit modification with a preliminary Finding of No Significant Impact.  OSM has stated their commitment to completing the court ordered remedial environmental assessment within the time prescribed by the court on or before September 6, 2015.

 

NOTE 12 – NEW ACCOUNTING PRONOUNCEMENTS

 

In February 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-02, Consolidation (Topic 810), Amendments to the Consolidation Analysis.  The amendments in this ASU affect reporting entities that are required to evaluate whether they should consolidate certain legal entities.  All legal entities are subject to reevaluation under the revised consolidation model.  Specifically, ASU 2015-02:  (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, and (3) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships.  For public business entities, ASU 2015-02 is effective for the fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015.  Early adoption is permitted, including adoption in an interim period.  A reporting entity may apply the amendments in this ASU using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption.  A reporting entity also may apply the amendments retrospectively.  We are currently considering the impact of this amendment on our financial position and results of operations.

 

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606).  This amendment replaces current revenue guidance, based on risks and rewards, with a transfer of control model.  The core principle under this new model states that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.  To achieve the core principle, ASU 2014-09 requires the following steps:  (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when (or as) the entity satisfies a performance obligation.  ASU 2014-09 also requires additional quantitative and qualitative disclosures sufficient enough to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.  For public business entities, ASU 2014-09 was originally effective for the fiscal year beginning January 1, 2017 using either of the following transition methods:  (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes footnote disclosures).  In August, 2015, the FASB issued ASU 2015-14, Revenue From Contracts With Customers (Topic 606): Deferral of the Effective Date, that defers the effective date of the new revenue standard by one year (January 1, 2018 effective date).  Reporting entities have the option to adopt the standard as early as the original January 1, 2017 effective date.  We are currently evaluating the impact of this amendment on our financial position and results of operations.

 

14


 

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

 

Overview

 

We are a taxable wholesale electric power generation and transmission cooperative incorporated in 1952 and operating on a not-for-profit basis.  We are organized for the purpose of providing electricity to our 44 member distribution systems, or Members, that serve major parts of Colorado, Nebraska, New Mexico and Wyoming.  We also sell a portion of our generated electric power to other utilities in the region pursuant to long-term contracts and spot sale arrangements.  Our Members provide retail electric service to rural residences, farms and ranches, cities, towns and suburban communities, as well as large and small businesses and industries.  In 2014, our Members served approximately 614,000 retail electric meters over a 200,000 square-mile area with a population of approximately 1.5 million people.  We sold 8.5 million MWhs for the six months ended June 30, 2015, of which 87 percent was to Members.  Total revenue from electric sales was $589.7 million for the six months ended June 30, 2015, of which 89 percent was from Member sales.

 

We have entered into substantially similar contracts with each Member extending through 2050 for 42 Members and extending through 2040 for the remaining two Members, and subject to automatic extension thereafter until either party provides at least a two year notice of its intent to terminate.  Each contract obligates us to sell and deliver to the Member and obligates the Member to purchase and receive at least 95 percent of its electric power requirements from us.  Each Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled by the Member.  As of June 30, 2015, 16 Members have enrolled in this program with capacity totaling approximately 72 MWs.

 

We supply and transmit our Members’ electric power requirements through a portfolio of resources, including generating stations, long-term purchase contracts, and forward, short-term and spot market energy purchases.  We own, lease, have undivided percentage interests in, or have tolling arrangements with respect to, various generating stations.  Additionally, we transmit power to our Members through resources that we own, lease or have undivided percentage interests in, or by wheeling power across lines owned by other transmission providers.

 

Summary of Significant Accounting Policies

 

As of June 30, 2015, there have been no material changes in our significant accounting policies as disclosed in our 2014 notes to consolidated financial statements. 

 

Factors Affecting Results

 

Margins and Patronage Capital

 

We operate on a cooperative basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to meet certain financial requirements and to establish reasonable reserves.  Revenues in excess of current period costs in any year are designated as net margins in our statement of operations.  Net margins are treated as advances of capital by our Members and are allocated to our Members on the basis of revenue from electricity purchases from us.  Net losses, should they occur, are not allocated to our Members but are offset by future margins.

 

Our Financial Goals and Capital Credits Policy, approved and subject to change by our Board of Directors, sets guidelines to achieve margins and retain patronage capital sufficient to maintain a sound financial position and to allow for the orderly retirement of capital credits allocated to our Members.  Pursuant to the policy, we target rates payable by our Members to produce financial results in excess of the requirements under our indenture, dated effective as of December 15, 1999, or Master Indenture, between us and Wells Fargo Bank, National Association, as trustee.  On a periodic basis, our Board of Directors evaluates liquidity goals and equity goals (that are a part of the Financial Goals and Capital Credits Policy) in determining the timing and amount of patronage capital retirement, and if the Board of Directors determines that our financial condition will not be impaired, a portion of retained patronage capital may be retired.  Historically, patronage capital has been retired in order of priority according to the year in which the patronage capital was furnished and credited; however, our bylaws were recently amended to provide the Board of Directors’

15


 

discretion on order of retirement.  As of June 30, 2015, patronage capital equity is $935.1 million.  To date, we have retired approximately $303 million of patronage capital to our Members.

 

Rates and Regulation

 

Our electric sales revenues are derived from electric power sales to our Members and non-member purchasers.  Rates for electric power sales to our Members consist of two billing components: an energy rate and a demand rate.  Member rates for energy and demand are set by our Board of Directors, consistent with adequate electrical reliability and sound fiscal policy.  Energy is the physical electricity delivered through the transmission and distribution system to customers.  Beginning January 1, 2013, we implemented a new rate design (A-37 rate) that incorporates a seasonal average demand rate, which is calculated by dividing each Member’s total monthly energy (kWh) usage by the total hours in the month.  The new rate design also has a new energy rate that incorporates an on-peak/off-peak factor.  The new rate schedule is then adjusted for demand response and energy shaping product incentives for Members utilizing those products.  In November 2014, we implemented an optional rate available to our non-New Mexico Members, effective December 1, 2014 through December 31, 2015, with the energy rate billed based upon a price per kWh of energy delivered and the demand billed based upon our Member’s highest thirty-minute integrated total demand measured using the Member’s coincident peak during our peak period in each monthly billing period during our summer peak period or the winter peak period.  As of June 30, 2015, three Members have elected this optional rate. 

 

Although rates established by our Board of Directors are generally not subject to regulation by federal, state or other governmental agencies, we are currently required to submit our rates to the New Mexico Public Regulation Commission, or NMPRC.  We are also involved in proceedings pending in New Mexico and Colorado regarding efforts by the NMPRC and the Colorado Public Utilities Commission, or COPUC, related to our wholesale rates payable by our Members.

 

As required by New Mexico law, we file our rates to our New Mexico Members with the NMPRC, which has regulatory authority over rate increases in New Mexico, only in the event three or more of our New Mexico Members file a request for such a review and such review is found to be qualified by the NMPRC.  In November 2012, three of our Members located in New Mexico filed protests with the NMPRC of the new rate that we filed with the NMPRC on October 19, 2012 and which was scheduled to become effective on January 1, 2013.  The rate would have increased revenue collected from our 44 Members by approximately 4.9 percent and from our 12 New Mexico Members by approximately 6.7 percent.  On December 20,  2012, the NMPRC suspended the rate filing in New Mexico and appointed a hearing examiner to conduct a hearing and establish reasonable rate schedules pursuant to New Mexico law.  In June 2013, we attempted to withdraw the 2013 wholesale rate notice in New Mexico because our development and implementation of a new 2014 rate would likely be complete prior to NMPRC action on the suspended 2013 rate.  The NMPRC suspended consideration of the 2013 rate but did not permit the withdrawal of the rate.  On September 10, 2013, we gave notice, as required by New Mexico law, to the NMPRC of our new wholesale rate which was scheduled to become effective on January 1, 2014, or the A-38 rate.  Four Members filed protests with the NMPRC challenging the A-38 rate.  The A-38 rate modified the rate design but did not increase the general revenue requirement.  On December 11, 2013, the NMPRC suspended the A-38 rate filing and assigned the consolidated A-37 and A-38 rate filings to a hearing examiner.  In August 2014, we and the New Mexico Members executed a preliminary mediation agreement providing for a temporary rate rider through no later than December 31, 2015 (unless terminated earlier as provided in the preliminary mediation agreement) and a suspension of the procedural schedule related to the rate protest to allow the parties time to proceed with more extensive discussions on a global settlement.  We filed notice of the temporary rate rider with the NMPRC and it became effective on October 2, 2014.  The temporary rate rider is applied in conjunction with the 2012 wholesale rate to recover additional revenue from the New Mexico Members in an annualized amount of $7 million per year, which was prorated beginning October 2 for 2014.  The overall impact of the New Mexico Members paying a lower rate was approximately $3.1 and $5.0 million for the three and six months ended June 30, 2015, respectively.

 

On March 4, 2013, three of our Colorado Members and several of their large industrial customers filed a complaint at the COPUC alleging that the A-37 rate design was unjust and unreasonable.  On April 4, 2013, we filed a motion to dismiss the complaint arguing lack of jurisdiction by the COPUC over our wholesale rates.  The COPUC assigned the matter to an administrative law judge.  The judge bifurcated the case into deciding first, whether the COPUC had the jurisdiction

16


 

to hear such a case against us, who has been historically regulated by its membership through its Board of Directors, and secondly to hear the facts in the case depending on jurisdiction.  The administrative law judge conducted a hearing in July 2013 and ruled on September 11, 2013 denying our motion to dismiss.  In October 2013, we appealed the administrative law judge’s decision to the full commission and on December 18, 2013, the commission granted in part and denied in part our motion contesting the administrative law judge’s decision and remanded the case to the administrative law judge to hold a hearing on limited issues.  In November 2014, we and the three Colorado Members executed a preliminary agreement providing for a temporary optional rate effective December 1, 2014 and to continue through no later than December 31, 2015, available to all non-New Mexico Members and a suspension of the procedural schedule related to the complaint.  The administrative law judge entered a decision on November 28, 2014 holding this matter in abeyance until December 31, 2015 to give the parties time to work toward a global settlement and permanent rate.

 

Master Indenture

 

As of June 30, 2015, we had approximately $2.8 billion of secured indebtedness outstanding under the Master Indenture.  Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under the Master Indenture.  The Master Indenture requires us to establish rates annually that are designed to maintain a Debt Service Ratio (as defined in the Master Indenture), or DSR, of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historic and pro forma basis.  The Master Indenture also requires us to maintain an Equity to Capitalization Ratio (as defined in the Master Indenture), or ECR, at the end of each fiscal year of 14 percent through 2015, and 18 percent thereafter. 

 

Tax Status

 

We are a taxable cooperative subject to federal and state taxation.  As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital.  We utilize the liability method of accounting for income taxes.  Accordingly, changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability.  A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.

 

Results of Operations

 

General

 

Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather, seasonal factors, load requirements in our Members’ service territories, operating costs, availability of generating stations, and our decision whether to dispatch our own resources or make spot market energy purchases.

 

We currently anticipate that continued growth in our Members’ energy requirements will occur.  Much of this growth is related to the large commercial sector, due to increased natural gas, crude oil, and carbon dioxide extraction, processing and transportation.  We forecast that our Member load will grow at an average of approximately 2.0 to 3.0 percent annually over the next five years.

 

 

Three months ended June 30, 2015 compared to three months ended June 30, 2014

 

Operating Revenues

 

Member electric sales increased 42,634 MWhs, or 1.2 percent, to 3,625,020 MWhs for the three months ended June 30, 2015 compared to 3,582,386 MWhs for the same period in 2014.  The increase in MWhs sold in 2015 resulted in an increase of $1.0 million in Member electric sales revenue to $257.3 million for the three months ended June 30, 2015 compared to $256.3 million for the same period in 2014.  One of the largest contributors to the increase in revenue was a $5.5 million increase in Member electric sales resulting from one of our Members adding oil and gas loads

17


 

beginning in mid-2014.  Also, one of our Members started serving the City of Gallup, NM in June 2014, resulting in a $1.7 million increase in Member electric sales revenue for the three months ended June 30, 2015.  The increases in Member electric sales during the second quarter of 2015 were partially offset by a 2.4 percent decrease in irrigation loads due to above average precipitation during the growing season.

 

Non-member electric sales decreased 325,889 MWhs, or 37.4 percent, to 546,088 MWhs for the three months ended June 30, 2015 compared to 871,977 MWhs for the same period in 2014.  Non-member electric sales revenue decreased $20.8 million, or 41.1 percent, to $29.8 million for the three months ended June 30, 2015 compared to $50.6 million for the same period in 2014.  The decrease in non-member electric sales revenue was largely due to a $12.5 million decrease in long-term firm energy sales to non-members and a $3.0 million decrease in short-term market sales.  The decrease in long-term firm energy sales to non-members was due to the expiration of several power sales arrangements on February 1, 2015 and September 30, 2014 that were not renewed resulting in a decrease in non-member electric sales revenue of $11.6 million (a decrease of 254,564 MWhs sold) for the three months ended June 30, 2015 compared to the same period in 2014.  When a power generating station is initially placed into service, there is generally a period of time when sales from such stations are not needed to serve our Members.  In such cases, we may enter into contracts with non-members, which provide revenue to us during such periods and reduce the Member revenue requirements.  We generally try to time the expiration of these contracts to coincide with forecasted increased Member demand, which has the effect of reducing non-member sales following such expirations.  As a result, we determined not to renew the two agreements upon their expiration.  The decrease in long-term firm energy sales was partially offset by a $1.9 million increase in non-member electric sales revenue resulting from non-member sales to the City of Farmington, NM beginning in January 2015.  The decrease in short-term market sales was due to lower market prices and a 62,102 MWh decrease in MWhs sold for the three months ended June 30, 2015 compared to the same period in 2014.  Additionally, there was a $5.0 million decrease in non-member electric sales revenue due to the recognition in the three months ended June 30, 2014 of $5.0 million of regulatory liabilities previously recorded for deferred non-member electric sales revenue and there being no such recognition in the three months ended June 30, 2015.  The recognition in 2014 resulted in reduced Member revenue requirements (lower Member rates) as was required in 2014 by our Board of Directors in accordance with its budgetary and rate-setting authority.

 

Operating Expenses

 

Fuel expense includes coal, natural gas and other fuel consumed at the generating stations.  Fuel expense decreased $34.8 million, or 49.5 percent, to $35.6 million for the three months ended June 30, 2015 compared to $70.4 million for the same period in 2014.  The decrease in expense was primarily due to lower coal expense resulting from the one-time recognition of $24.4 million as a reduction to fuel expense because of the BNSF rate settlement and a $14.9 million reduction in fuel expense for Craig Generating Station Unit 3 resulting from a scheduled maintenance outage in the second quarter of 2015.  These decreases were partially offset by a $2.8 million increase in natural gas expense resulting from an increase in generation at our natural gas-fired generating stations. 

 

Production expense includes the operation costs for the generating stations and generation maintenance expenses for maintaining the generating stations, such as costs of scheduled maintenance outages.  Production expense increased $9.2 million, or 15.1 percent, to $70.4 million for the three months ended June 30, 2015 compared to $61.2 million for the same period in 2014.  The increase in expense was primarily due to a $10.5 million increase in generation maintenance expenses resulting from scheduled maintenance outages at our Craig and Escalante Generating Stations and the Laramie River Station.

 

Depreciation and amortization expense increased $4.8 million, or 15.3 percent, to $36.0 million for the three months ended June 30, 2015 compared to $31.2 million for the same period in 2014.  The increase in expense was primarily due to amortization of transaction costs that we incurred related to the prepayment of our long-term debt in 2014.  These costs, accounted for as a regulatory asset, are being amortized over the 21.4-year average life of the new debt issued and recovered from our Members in rates.

 

18


 

Other Income

 

Interest income decreased $2.0 million, or 64.4 percent, to $1.1 million for the three months ended June 30, 2015 compared to $3.1 million for the same period in 2014.  The decrease in interest income was primarily due to there being no investment during 2015 in the United States Department of Agriculture’s Rural Utilities Service, or RUS, cushion of credit, which earned a 5 percent return.  The investment in the RUS cushion of credit was eliminated by the 2014 debt refinancing (completed fourth quarter 2014) when our RUS debt and Federal Financing Bank debt was entirely paid off. 

 

Six months ended June 30, 2015 compared to six months ended June 30, 2014

 

Operating Revenues

 

Member electric sales increased 111,844 MWhs, or 1.5 percent, to 7,408,706 MWhs for the six months ended June 30, 2015 compared to 7,296,862 MWhs for the same period in 2014.  The increase in MWhs sold in 2015 resulted in an increase of $4.0 million, in Member electric sales revenue to $524.9 million for the six months ended June 30, 2015 compared to $520.9 million for the same period in 2014.  One of the largest contributors to the increase in revenue was a $12.8 million increase in Member electric sales resulting from one of our Members adding oil and gas loads beginning in mid-2014.  Also, one of our Members started serving the City of Gallup, NM in June 2014, resulting in a $3.8 million increase in Member electric sales revenue for the six months ended June 30, 2015.

 

Non-member electric sales decreased 732,775 MWhs, or 39.2 percent, to 1,137,412 MWhs for the six months ended June 30, 2015 compared to 1,870,187 MWhs for the same period in 2014.  Non-member electric sales revenue decreased $45.2 million, or 41.1 percent, to $64.9 million for the six months ended June 30, 2015 compared to $110.1 million for the same period in 2014.  The decrease in non-member electric sales revenue was primarily due to a $24.1 million decrease in long-term firm energy sales to non-members and a $11.0 million decrease in short-term market sales.  The decrease in long-term firm energy sales to non-members was due to the expiration of several power sales arrangements on February 1, 2015 and September 30, 2014 that were not renewed resulting in a decrease in non-member electric sales revenue of $23.8 million (a decrease of 493,173 MWhs sold) for the six months ended June 30, 2015 compared to the same period in 2014.  When a power generating station is initially placed into service, there is generally a period of time when sales from such stations are not needed to serve our Members.  In such cases, we may enter into contracts with non-members, which provide revenue to us during such periods and reduce the Member revenue requirements.  We generally try to time the expiration of these contracts to coincide with forecasted increased Member demand, which has the effect of reducing non-member sales following such expirations.  As a result, we determined not to renew the two agreements upon their expiration.  The decrease in long-term firm energy sales was partially offset by a $3.8 million increase in non-member electric sales revenue resulting from non-member sales to the City of Farmington, NM beginning in January 2015.  The decrease in short-term market sales was due to lower market prices and a 258,576 MWh decrease in MWhs sold for the six months ended June 30, 2015 compared to the same period in 2014.  Additionally, there was a $10.0 million decrease in non-member electric sales revenue due to the recognition in the six-months ended June 30, 2014 of $10.0 million of regulatory liabilities previously recorded for deferred non-member electric sales revenue and there being no such recognition in the six-months ended June 30, 2015.  The recognition in 2014 resulted in reduced Member revenue requirements (lower Member rates) as was required in 2014 by our Board of Directors in accordance with its budgetary and rate-setting authority.

 

Operating Expenses

 

Purchased power increased 13,749 MWhs to 3,269,290 MWhs for the six months ended June 30, 2015 compared to 3,255,541 MWhs for the same period in 2014.  Despite this 0.4 percent increase in MWhs purchased in 2015, purchased power expense decreased $8.0 million, or 5.3 percent, to $144.4 million for the six months ended June 30, 2015 compared to $152.4 million for the same period in 2014 as a result of a 6.0 percent decrease in the average cost per MWh due to lower market prices. 

 

Fuel expense decreased $47.5 million, or 32.9 percent, to $96.8 million for the six months ended June 30, 2015 compared to $144.3 million for the same period in 2014.  The decrease in expense was primarily due to lower coal expense resulting from a one-time recognition of $24.4 million as a reduction in fuel expense because of the BNSF rate

19


 

settlement and a $17.1 million reduction in fuel expense for Craig Generating Station Unit 3 resulting from a scheduled maintenance outage in the second quarter of 2015.

 

Production expense increased $9.7 million, or 8.5 percent, to $123.9 million for the six months ended June 30, 2015 compared to $114.2 million for the same period in 2014.  The increase in expense was primarily due to a $10.5 million increase in generation maintenance expenses resulting from scheduled maintenance outages at our Craig and Escalante Generating Stations and at the Laramie River Station.

 

Depreciation and amortization expense increased $8.8 million, or 14.3 percent, to $70.9 million for the six months ended June 30, 2015 compared to $62.1 million for the same period in 2014.  The increase in expense was primarily due to additions of equipment throughout our transmission system and at our generating stations.  Additionally, amortization expense increased in 2015 resulting from the amortization of transaction costs that we incurred related to the prepayment of our long-term debt in 2014.  These costs are being amortized over the 21.4-year average life of the new debt issued and recovered from our Members in rates.

 

Coal mining expense includes the Colowyo Mine operating expenses related to the portion of the coal sold from the Colowyo Mine to other joint owners in the Yampa Project pursuant to a contract expiring in 2017.  Coal mining expense decreased $5.5 million, or 25.7 percent, to $15.9 million for the six months ended June 30, 2015 compared to $21.4 million for the same period in 2014.  The primary driver for the coal mining expense decrease has been the lower per ton production costs experienced in 2015 due to the increase in coal production activity at the Colowyo Mine for the first six months of 2015 as compared to the first six months of 2014.  Additionally, the tons of coal sold for the comparable periods were relatively flat.

 

Other Income

 

Interest income decreased $4.1 million, or 65.7 percent, to $2.2 million for the six months ended June 30, 2015 compared to $6.3 million for the same period in 2014.  The decrease in interest income was primarily due to there being no investment during 2015 in the RUS cushion of credit, which earned a 5 percent return. 

 

Capital credits from cooperatives consist of patronage capital allocations received from other cooperatives of which we are a member, including cooperative banks, electric suppliers and service companies.  Capital credits increased $3.2 million, or 157.2 percent, to $5.2 million for the six months ended June 30, 2015 compared to $2.0 million for the same period in 2014.  The increase in capital credits was primarily due to higher allocations from Trapper Mining of $2.3 million and CoBank, ACB of $450,000.

 

Financial condition as of June 30, 2015 compared to December 31, 2014

 

Assets

 

Construction work in progress increased $59.7 million, or 29.0 percent, to $265.8 million as of June 30, 2015 compared to $206.1 million as of December 31, 2014.  The increase was primarily due to capital expenditures related to various generation and transmission capital improvements and system upgrades.

 

Other plant consists of non-utility property and the mine assets at Colowyo Mine and New Horizon Mine.  Other plant increased $17.7 million, or 8.4 percent, to $228.4 million as of June 30, 2015 compared to $210.7 million as of December 31, 2014.  The increase was primarily due to the acquisition of land and water rights in northwestern Colorado related to the Colowyo Mine.

 

Restricted cash and investments consist of (1) funds designated by our Board of Directors for specific uses, (2) funds restricted by contract or other legal reasons, and (3) investments in securities pledged as collateral in connection with the in-substance defeasance of debt assumed in the 2011 acquisition of Colowyo Coal.  The current portion of restricted cash and investments decreased $34.4 million, or 87.4 percent, to $5.0 million as of June 30, 2015 compared to $39.4 million as of December 31, 2014.  The decrease was primarily due to the BNSF settlement which resolved the uncertainties related to the outcome of this matter and the $29.4 million of cash related to the BNSF settlement was no longer

20


 

designated as restricted.  Additionally, $4.2 million of investment in securities pledged as collateral matured during the second quarter of 2015.  The matured U.S. Treasury Notes were used for the Colowyo Bonds principal and interest due in May 2015.

 

Cash and cash equivalents increased $11.3 million, or 12.3 percent, to $103.8 million as of June 30, 2015 compared to $92.5 million as of December 31, 2014.  The increase was primarily due to $175.4 million of proceeds from issuance of debt partially offset by debt payments of $92.1 million, an increase in coal inventory of $21.9 million, primarily due to the Craig Generating Station Unit 3 outage, and an increase in capital expenditures of $67.0 million.

 

Coal inventory increased $21.9 million, or 53.9 percent, to $62.6 million as of June 30, 2015 compared to $40.7 million as of December 31, 2014.  The increase was primarily due to (1) a $11.4 million, or 70.5 percent, increase in coal inventory at our Craig Gener