10-Q 1 tris-20190930x10q.htm 10-Q tris_Current folio_10Q

 

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 September 30, 2019

 

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. 333-212006

 

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
No.)

 

 

1100 West 116th Avenue

 

Westminster, Colorado

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     (Note: The registrant is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), but voluntarily files reports with the Securities and Exchange Commission. The registrant has filed all Exchange Act reports for the preceding 12 months (or for such shorter period that the registrant was required to file such reports)).

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes     No 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer     Accelerated filer     Non-accelerated filer     Smaller reporting company     Emerging growth company 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 

 

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

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

 

 

 

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

None

None

None

 

Indicate the number of shares outstanding of each of the issuer’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 SEPTEMBER 30, 2019

 

 

 

 

 

    

Page Number

PART I.  FINANCIAL INFORMATION 

 

Item 1. 

Financial Statements

 

 

Consolidated Statements of Financial Position as of September 30, 2019 (unaudited) and December 31, 2018

1

 

Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2019 and 2018 (unaudited)

2

 

Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2019 and 2018 (unaudited)

3

 

Consolidated Statements of Equity — Three and Nine Months Ended September 30, 2019 and 2018 (unaudited)

4

 

Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2019 and 2018 (unaudited)

5

 

Notes to Unaudited Consolidated Financial Statements For the Three and Nine Months Ended September 30, 2019 and 2018

6

Item 2. 

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

22

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

35

Item 4. 

Controls and Procedures

35

PART II.  OTHER INFORMATION 

 

Item 1. 

Legal Proceedings

35

Item 1A 

Risk Factors

36

Item 4. 

Mine Safety Disclosures

36

Item 6. 

Exhibits

36

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,” “forecast,” “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

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

    

September 30, 2019

    

December 31, 2018

 

ASSETS

 

 

(unaudited)

 

 

 

 

Property, plant and equipment

 

 

 

 

 

 

 

Electric plant

 

 

 

 

 

 

 

In service

 

$

6,049,319

 

$

5,899,128

 

Construction work in progress

 

 

147,490

 

 

207,732

 

Total electric plant

 

 

6,196,809

 

 

6,106,860

 

Less allowances for depreciation and amortization

 

 

(2,607,309)

 

 

(2,499,376)

 

Net electric plant

 

 

3,589,500

 

 

3,607,484

 

Other plant

 

 

408,777

 

 

384,650

 

Less allowances for depreciation, amortization and depletion

 

 

(112,488)

 

 

(110,939)

 

Net other plant

 

 

296,289

 

 

273,711

 

Total property, plant and equipment

 

 

3,885,789

 

 

3,881,195

 

Other assets and investments

 

 

 

 

 

 

 

Investments in other associations

 

 

162,738

 

 

161,487

 

Investments in and advances to coal mines

 

 

18,098

 

 

18,928

 

Restricted cash and investments

 

 

24,344

 

 

10,606

 

Intangible assets, net of accumulated amortization

 

 

 —

 

 

3,662

 

Other noncurrent assets

 

 

9,303

 

 

9,022

 

Total other assets and investments

 

 

214,483

 

 

203,705

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

95,919

 

 

116,858

 

Restricted cash and investments

 

 

168

 

 

126

 

Deposits and advances

 

 

42,811

 

 

29,641

 

Accounts receivable—Members

 

 

109,565

 

 

107,572

 

Other accounts receivable

 

 

21,554

 

 

22,434

 

Coal inventory

 

 

51,961

 

 

55,883

 

Materials and supplies

 

 

96,729

 

 

93,786

 

Total current assets

 

 

418,707

 

 

426,300

 

Deferred charges

 

 

 

 

 

 

 

Regulatory assets

 

 

462,038

 

 

437,377

 

Prepayment—NRECA Retirement Security Plan

 

 

28,205

 

 

31,837

 

Other

 

 

49,928

 

 

46,453

 

Total deferred charges

 

 

540,171

 

 

515,667

 

Total assets

 

$

5,059,150

 

$

5,026,867

 

EQUITY AND LIABILITIES

 

 

 

 

 

 

 

Capitalization

 

 

 

 

 

 

 

Patronage capital equity

 

$

1,076,503

 

$

1,015,754

 

Accumulated other comprehensive income

 

 

174

 

 

375

 

Noncontrolling interest

 

 

110,602

 

 

110,169

 

Total equity

 

 

1,187,279

 

 

1,126,298

 

Long-term debt

 

 

3,068,693

 

 

3,109,301

 

Total capitalization

 

 

4,255,972

 

 

4,235,599

 

Current liabilities

 

 

 

 

 

 

 

Member advances

 

 

12,378

 

 

13,988

 

Accounts payable

 

 

104,987

 

 

105,009

 

Short-term borrowings

 

 

227,182

 

 

204,145

 

Accrued expenses

 

 

29,678

 

 

40,285

 

Current asset retirement obligations

 

 

2,294

 

 

2,183

 

Accrued interest

 

 

47,761

 

 

32,070

 

Accrued property taxes

 

 

28,300

 

 

28,582

 

Current maturities of long-term debt

 

 

80,161

 

 

95,757

 

Total current liabilities

 

 

532,741

 

 

522,019

 

Deferred credits and other liabilities

 

 

 

 

 

 

 

Regulatory liabilities

 

 

128,439

 

 

137,369

 

Deferred income tax liability

 

 

17,173

 

 

18,098

 

Asset retirement obligations

 

 

65,990

 

 

54,589

 

Other

 

 

48,928

 

 

50,266

 

Total deferred credits and other liabilities

 

 

260,530

 

 

260,322

 

Accumulated postretirement benefit and postemployment obligations

 

 

9,907

 

 

8,927

 

Total equity and liabilities

 

$

5,059,150

 

$

5,026,867

 

 

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 September 30, 

 

Nine Months Ended September 30, 

 

 

    

2019

    

2018

    

2019

    

2018

    

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

Member electric sales

 

$

358,586

 

$

353,487

 

$

942,175

 

 

942,916

 

Non-member electric sales

 

 

28,339

 

 

31,004

 

 

71,843

 

 

62,925

 

Other

 

 

12,128

 

 

13,666

 

 

39,540

 

 

38,337

 

 

 

 

399,053

 

 

398,157

 

 

1,053,558

 

 

1,044,178

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased power

 

 

103,525

 

 

106,166

 

 

252,948

 

 

271,187

 

Fuel

 

 

67,374

 

 

67,840

 

 

204,271

 

 

168,081

 

Production

 

 

48,619

 

 

52,558

 

 

148,457

 

 

165,750

 

Transmission

 

 

42,305

 

 

40,291

 

 

122,329

 

 

122,255

 

General and administrative

 

 

12,978

 

 

6,398

 

 

35,887

 

 

22,923

 

Depreciation, amortization and depletion

 

 

40,590

 

 

38,977

 

 

116,879

 

 

118,620

 

Coal mining

 

 

1,675

 

 

637

 

 

7,824

 

 

637

 

Other

 

 

4,640

 

 

3,897

 

 

12,154

 

 

11,317

 

 

 

 

321,706

 

 

316,764

 

 

900,749

 

 

880,770

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating margins

 

 

77,347

 

 

81,393

 

 

152,809

 

 

163,408

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

 

1,364

 

 

1,323

 

 

4,156

 

 

3,762

 

Capital credits from cooperatives

 

 

1,186

 

 

1,272

 

 

4,520

 

 

5,472

 

Other

 

 

14,314

 

 

1,466

 

 

16,226

 

 

3,609

 

 

 

 

16,864

 

 

4,061

 

 

24,902

 

 

12,843

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net of amounts capitalized

 

 

38,030

 

 

38,377

 

 

113,954

 

 

115,380

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax benefit

 

 

(77)

 

 

(151)

 

 

(231)

 

 

(453)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net margins including noncontrolling interest

 

 

56,258

 

 

47,228

 

 

63,988

 

 

61,324

 

Net income attributable to noncontrolling interest

 

 

(1,113)

 

 

(830)

 

 

(3,239)

 

 

(2,454)

 

Net margins attributable to the Association

 

$

55,145

 

$

46,398

 

$

60,749

 

$

58,870

 

 

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 September 30, 

 

Nine Months Ended September 30, 

 

 

    

2019

    

2018

    

2019

    

2018

    

Net margins including noncontrolling interest

 

$

56,258

 

$

47,228

 

$

63,988

 

$

61,324

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Reclassification of unrealized gain on securities available for sale included in net margin

 

 

 —

 

 

 —

 

 

 —

 

 

(159)

 

Amortization of prior service cost (credit)

 

 

(10)

 

 

(20)

 

 

13

 

 

(59)

 

Unrecognized prior service cost

 

 

 —

 

 

 —

 

 

(214)

 

 

 —

 

Other comprehensive income (loss)

 

 

(10)

 

 

(20)

 

 

(201)

 

 

(218)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss) including noncontrolling interest

 

 

56,248

 

 

47,208

 

 

63,787

 

 

61,106

 

Net comprehensive income attributable to noncontrolling interest

 

 

(1,113)

 

 

(830)

 

 

(3,239)

 

 

(2,454)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss) attributable to the Association

 

$

55,135

 

$

46,378

 

$

60,548

 

$

58,652

 

 

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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

 

Nine Months Ended September 30, 

 

    

2019

    

2018

    

    

2019

    

2018

Patronage capital equity at beginning of period

 

$

1,021,358

 

$

1,015,492

 

 

$

1,015,754

 

$

1,003,020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net margins attributable to the Association

 

 

55,145

 

 

46,398

 

 

 

60,749

 

 

58,870

Patronage capital equity at end of period

 

 

1,076,503

 

 

1,061,890

 

 

 

1,076,503

 

 

1,061,890

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated other comprehensive income (loss) at beginning of period

 

 

184

 

 

(408)

 

 

 

375

 

 

(210)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reclassification adjustment for unrealized gain on securities available for sale included in net margin

 

 

 —

 

 

 —

 

 

 

 —

 

 

(159)

Amortization of prior service cost (credit)

 

 

(10)

 

 

(20)

 

 

 

13

 

 

(59)

Unrecognized prior service cost

 

 

 —

 

 

 —

 

 

 

(214)

 

 

 —

Accumulated other comprehensive income (loss) at end of period

 

 

174

 

 

(428)

 

 

 

174

 

 

(428)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noncontrolling interest at beginning of period

 

 

110,841

 

 

110,061

 

 

 

110,169

 

 

111,295

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net comprehensive income attributable to noncontrolling interest

 

 

1,113

 

 

830

 

 

 

3,239

 

 

2,454

Equity distribution to noncontrolling interest

 

 

(1,352)

 

 

(1,555)

 

 

 

(2,806)

 

 

(4,413)

Noncontrolling interest at end of period

 

 

110,602

 

 

109,336

 

 

 

110,602

 

 

109,336

Total equity at end of period

 

$

1,187,279

 

$

1,170,798

 

 

$

1,187,279

 

$

1,170,798

 

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)

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 

 

 

  

2019

  

2018

    

Operating activities

 

 

 

 

 

 

 

Net margins including noncontrolling interest

 

$

63,988

 

$

61,324

 

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

 

 

 

 

 

 

 

Depreciation, amortization and depletion

 

 

116,879

 

 

118,620

 

Amortization of intangible asset

 

 

3,662

 

 

5,493

 

Amortization of NRECA Retirement Security Plan prepayment

 

 

4,029

 

 

4,029

 

Amortization of debt issuance costs

 

 

1,773

 

 

2,210

 

Impairment loss - Nucla

 

 

37,067

 

 

 —

 

Deferred Nucla impairment loss

 

 

(37,067)

 

 

 —

 

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

 

 

(486)

 

 

(1,493)

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

 

 

(155)

 

 

(18,721)

 

Coal inventory

 

 

3,922

 

 

(27,040)

 

Materials and supplies

 

 

(2,943)

 

 

(1,854)

 

Accounts payable and accrued expenses

 

 

3,418

 

 

(8,734)

 

Accrued interest

 

 

15,691

 

 

17,696

 

Accrued property taxes

 

 

(282)

 

 

684

 

Other

 

 

(7,581)

 

 

(13,791)

 

Net cash provided by operating activities

 

 

201,915

 

 

138,423

 

 

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

 

 

Purchases of plant

 

 

(149,396)

 

 

(199,261)

 

Changes in deferred charges

 

 

(6,277)

 

 

(1,547)

 

Proceeds from other investments

 

 

65

 

 

64

 

Net cash used in investing activities

 

 

(155,608)

 

 

(200,744)

 

 

 

 

 

 

 

 

 

Financing activities

 

 

 

 

 

 

 

Changes in Member advances

 

 

(5,351)

 

 

257

 

Payments of long-term debt

 

 

(91,884)

 

 

(73,943)

 

Proceeds from issuance of long-term debt

 

 

34,910

 

 

60,000

 

Debt issuance costs

 

 

(13)

 

 

 —

 

Increase in short-term borrowings, net

 

 

23,036

 

 

61,530

 

Retirement of patronage capital

 

 

(11,101)

 

 

(4,852)

 

Equity distribution to noncontrolling interest

 

 

(2,806)

 

 

(4,413)

 

Other

 

 

(257)

 

 

(1,545)

 

Net cash provided by (used in) financing activities

 

 

(53,466)

 

 

37,034

 

 

 

 

 

 

 

 

 

Net decrease in cash, cash equivalents and restricted cash and investments

 

 

(7,159)

 

 

(25,287)

 

Cash, cash equivalents and restricted cash and investments – beginning

 

 

127,590

 

 

150,965

 

Cash, cash equivalents and restricted cash and investments – ending

 

$

120,431

 

$

125,678

 

 

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

 

 

Cash paid for interest

 

$

103,782

 

$

102,916

 

Cash paid for income taxes

 

$

 —

 

$

 —

 

 

 

 

 

 

 

 

 

Supplemental disclosure of noncash investing and financing activities:

 

 

 

 

 

 

 

Change in plant expenditures included in accounts payable

 

$

(873)

 

$

67

 

 

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 Nine Months Ended September 30, 2019 and 2018

 

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 (“GAAP”) 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 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 annual report on Form 10-K for the year ended December 31, 2018 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of September 30, 2019, results of operations for the three and nine months ended September 30, 2019 and 2018, and cash flows for the nine months ended September 30, 2019 and 2018 are not necessarily indicative of the results that may be expected for an entire year or any other period.

 

The accompanying financial statements reflect the consolidated accounts of Tri-State Generation and Transmission Association, Inc. (“Tri-State”, “we”, “our”, “us” or “the Association”), our wholly-owned and majority-owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 17 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities.

 

We are a taxable wholesale electric power generation and transmission cooperative, incorporated under the laws of the State of Colorado in 1952. As of September 30, 2019, we had two classes of members – all requirements electric members known as the Class A members and non-utility members. For our Class A members, we provide electric power to our forty-three electric distribution member systems (“Member(s)”) pursuant to long-term wholesale electric service contracts. On September 3, 2019, a membership agreement with a non-utility member, MIECO, Inc., became effective and we notified the Federal Energy Regulatory Commission (“FERC”) of such. The admission of the new member that was not an electric cooperative or governmental entity resulted in us no longer being exempt from FERC wholesale rate regulation pursuant to the Federal Power Act. Our sole non-utility member supplies natural gas to several of our generation facilities located in New Mexico and Colorado. We have eliminated all significant intercompany balances and transactions in consolidation.

 

Jointly Owned Facilities

 

We own undivided interests in two 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) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). 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 other operating expenses is included in our consolidated financial statements.

 

6

Our share in each jointly owned facility is as follows as of September 30, 2019 (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

                  

  

Electric

  

 

 

  

Construction

 

 

Tri-State

 

Plant in

 

Accumulated

 

Work In

 

 

Share

 

Service

 

Depreciation

 

Progress

Yampa Project - Craig Generating Station Units 1 and 2

 

24.00

%  

$

396,111

 

$

243,788

 

$

65

MBPP - Laramie River Station

 

27.13

%

 

487,049

 

 

297,800

 

 

3,961

Total

 

 

 

$

883,160

 

$

541,588

 

$

4,026

 

 

 

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 (“Board”) if it is probable that these amounts will be refunded or recovered through future rates. Prior to September 3, 2019, our Board had sole budgetary and rate-setting authority. On September 3, 2019, we became a  FERC jurisdictional public utility and our Board’s rate setting authority is now subject to FERC approval. Regulatory assets are costs that we expect to recover from our Members based on rates approved by the applicable authority. 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 the applicable authority. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery in rates.

 

Regulatory assets and liabilities are as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31,

 

 

    

2019

    

2018

 

Regulatory assets

 

 

 

 

 

 

 

Deferred income tax expense (1)

 

$

17,173

 

$

18,098

 

Deferred prepaid lease expense – Springerville Unit 3 Lease (2)

 

 

84,287

 

 

86,005

 

Goodwill – J.M. Shafer (3)

 

 

49,857

 

 

51,994

 

Goodwill – Colowyo Coal (4)

 

 

37,453

 

 

38,227

 

Deferred debt prepayment transaction costs (5)

 

 

143,088

 

 

149,559

 

Deferred Holcomb expansion impairment loss (6)

 

 

93,494

 

 

93,494

 

Deferred Nucla impairment loss (7)

 

 

36,686

 

 

 —

 

Total regulatory assets

 

 

462,038

 

 

437,377

 

 

 

 

 

 

 

 

 

Regulatory liabilities

 

 

 

 

 

 

 

Interest rate swap - unrealized gain (8)

 

 

 —

 

 

8,576

 

Interest rate swap - realized gain (9)

 

 

3,861

 

 

4,215

 

Deferred revenues (10)

 

 

82,006

 

 

82,006

 

Membership withdrawal (11)

 

 

42,572

 

 

42,572

 

Total regulatory liabilities

 

 

128,439

 

 

137,369

 

Net regulatory asset

 

$

333,599

 

$

300,008

 

 

(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)

Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville 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, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Members in rates.

(3)

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

7

(4)

Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Members in rates.

(5)

Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Members in rates.

(6)

Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. Beginning January 2020, the deferred impairment loss is expected be amortized to other operating expenses in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Members in rates.

(7)

In July 2019, the Board took action for the early retirement of the Nucla Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $37.1 million during the third quarter of 2019. On September 19, 2019, the Nucla Generating Station was officially retired from service. The deferred impairment loss is being amortized to depreciation, amortization and depletion expense over the 3.3-year period ending in December 2022 and recovered from our Members in rates.

(8)

Represented deferral of an unrealized gain related to the change in fair value of a forward starting interest rate swap that was entered into in 2016 in order to hedge interest rates on anticipated future borrowings. This interest rate swap was terminated in June 2019 with no gain or loss being realized.

(9)

Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Members through reduced rates when recognized in future periods.

(10)

Represents deferral of the recognition of non-member electric sales revenues. 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.

(11)

Represents the deferral of the recognition of other income recorded in connection with the withdrawal of a former Member from membership in us. This deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods.

 

 

NOTE 3 – INVESTMENTS IN OTHER ASSOCIATIONS  

 

Investments in other associations include investments in the patronage capital of other cooperatives and other required investments in the organizations. 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. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative.

 

Investments in other associations are as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

    

2019

    

2018

 

Basin Electric Power Cooperative

 

$

118,115

 

$

118,115

 

National Rural Utilities Cooperative Finance Corporation - patronage capital

 

 

11,761

 

 

11,704

 

National Rural Utilities Cooperative Finance Corporation - capital term certificates

 

 

15,953

 

 

16,018

 

CoBank, ACB

 

 

10,201

 

 

9,062

 

Western Fuels Association, Inc.

 

 

2,408

 

 

2,392

 

Other

 

 

4,300

 

 

4,196

 

Investments in other associations

 

$

162,738

 

$

161,487

 

 

Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during the nine months ended September 30, 2019 or during 2018.

8

 

NOTE 4 – INVESTMENTS IN AND ADVANCES TO COAL MINES  

 

We have direct ownership and investments in coal mines to support our coal generating resources. We, and certain participants in the Yampa Project, are members of Trapper Mining, which is organized as a cooperative and is the owner and operator of the Trapper Mine near Craig, Colorado. Our investment in Trapper Mining is recorded using the equity method. In addition, we have ownership in Western Fuels Association, Inc. (“WFA”), which is an owner of Western Fuels‑Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. Dry Fork Mine provides coal to the Laramie River Generating Station (owned by the participants of MBPP). We, through our undivided interest in the jointly owned facility of MBPP, advance funds to the Dry Fork Mine.

 

Investments in and advances to coal mines are as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31,

 

 

    

2019

    

2018

 

Investment in Trapper Mine

 

$

15,748

 

$

15,350

 

Advances to Dry Fork Mine

 

 

2,350

 

 

3,578

 

Investments in and advances to coal mines

 

$

18,098

 

$

18,928

 

 

 

NOTE 5 – CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS    

 

We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity.

 

Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds are amounts that have been restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on our consolidated statements of financial position. The other funds are for amounts restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on our consolidated statements of financial position.

 

The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

  

September 30, 

 

December 31,

 

 

    

2019

    

2018

 

Cash and cash equivalents

 

$

95,919

 

$

116,858

 

Restricted cash and investments - current

 

 

168

 

 

126

 

Restricted cash and investments - noncurrent

 

 

24,344

 

 

10,606

 

Cash, cash equivalents and restricted cash and investments

 

$

120,431

 

$

127,590

 

 

Our Board Policy for Financial Goals and Capital Credits was revised in 2018 to provide that our Board will endeavor to fund an internally restricted cash account for the purpose of cash funding deferred revenues and incomes held as regulatory liabilities. In connection with such policy, our Board has internally restricted cash in the amount of $19.4 million and $4.6 million as of September 30, 2019 and December 31, 2018, respectively, which is included in restricted cash and investments - noncurrent.

 

9

 

 

NOTE 6 – CONTRACT ASSETS AND CONTRACT LIABILITIES

 

Accounts Receivable

 

We record accounts receivable for our unconditional rights to consideration arising from our performance under contracts with our Members and other parties. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible. See Note 13 – Revenue.

 

Contract liabilities (unearned revenue)

 

A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in unearned revenue (included in other deferred credits and other liabilities on our consolidated statements of financial position) before revenue is recognized, resulting in contract liabilities. During the nine months ended September 30, 2019, we recognized $0.6 million of this unearned revenue in other operating revenues on our consolidated statements of operations.

 

Our contract assets and liabilities consist of the following (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

  

2019

    

2018

    

Accounts receivable - Members

 

$

109,565

 

$

107,572

 

 

 

 

 

 

 

 

 

Other accounts receivable - trade:

 

 

 

 

 

 

 

Non-member electric sales

 

 

5,465

 

 

6,998

 

Other

 

 

14,974

 

 

6,006

 

Total other accounts receivable - trade

 

 

20,439

 

 

13,004

 

Other accounts receivable - nontrade

 

 

1,115

 

 

9,430

 

Total other accounts receivable

 

$

21,554

 

$

22,434

 

 

 

 

 

 

 

 

 

Contract liabilities (unearned revenue)

 

$

7,257

 

$

7,906

 

 

Other accounts receivable increased primarily due to a retroactive royalty rate reduction granted to Colowyo Mine by the Office of Natural Resources Revenue. The decision reduces the royalty rate from 12.5 percent to 8 percent for coal extracted under certain leases from September 1, 2015 through June 30, 2019.

 

 

 

NOTE 7 – OTHER DEFERRED CHARGES  

 

The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

    

2019

    

2018

 

Preliminary surveys and investigations

 

$

22,214

 

$

20,660

 

Advances to operating agents of jointly owned facilities

 

 

19,662

 

 

13,161

 

Interest rate swap

 

 

 —

 

 

8,576

 

Operating lease right-of-use assets

 

 

3,798

 

 

 —

 

Other

 

 

4,254

 

 

4,056

 

Total other deferred charges

 

$

49,928

 

$

46,453

 

 

We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation

10

expenditures will be reclassified to electric plant ‑ construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account. The expense could be deferred as a regulatory asset to be recovered from our Members in rates subject to approval by the applicable authority.

 

We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3.

 

In 2016, we entered into a forward starting interest rate swap to hedge a portion of our future long-term debt interest rate exposure. The unrealized gain on this interest rate swap of $8.6 million as of December 31, 2018 was deferred in accordance with the accounting requirements related to regulated operations. See Note 2 – Accounting for Rate Regulation. This interest rate swap was terminated in June 2019 with no gain or loss being realized.

 

A right-of-use asset represents a lessee’s right to control the use of the underlying asset for the lease term. Right-of-use assets are included in other deferred charges and presented net of accumulated amortization. See Note 15 – Leases.

 

 

 

NOTE 8 – LONG-TERM DEBT

 

We have $3.1 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. 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 (“Master Indenture”) except for one unsecured note in the amount of $28.9 million as of September 30, 2019. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement and equity to capitalization ratio requirement.

 

We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation, as lead arranger and administrative agent, in the amount of $650 million (“2018 Revolving Credit Agreement”) that expires on April 25, 2023. We had no outstanding borrowings under the 2018 Revolving Credit Agreement as of September 30, 2019. As of September 30, 2019, we had $422.0 million in availability (including $272.0 million under the commercial paper back-up sublimit) under the 2018 Revolving Credit Agreement.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

    

2019

  

2018

 

Total debt

 

$

3,170,688

 

$

3,227,663

 

Less debt issuance costs

 

 

(28,014)

 

 

(29,775)

 

Less debt discounts

 

 

(9,966)

 

 

(10,139)

 

Plus debt premiums

 

 

16,146

 

 

17,309

 

Total debt adjusted for debt issuance costs, discounts and premiums

 

 

3,148,854

 

 

3,205,058

 

Less current maturities

 

 

(80,161)

 

 

(95,757)

 

Long-term debt

 

$

3,068,693

 

$

3,109,301

 

 

 

NOTE 9 – SHORT-TERM BORROWINGS   

 

We have a commercial paper program under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper back-up sublimit under our 2018 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 2018 Revolving Credit Agreement. The commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary, but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on our consolidated statements of financial position.

11

 

Commercial paper consisted of the following (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

    

2019

    

2018

 

Commercial paper outstanding, net of discounts

 

$

227,182

 

$

204,145

 

Weighted average interest rate

 

 

2.21

%

 

2.65

%

 

At September 30, 2019, $272.0 million of the commercial paper back-up sublimit remained available under the 2018 Revolving Credit Agreement. See Note 8 – Long-Term Debt.

 

 

NOTE 10 – ASSET RETIREMENT OBLIGATIONS   

 

We account for current obligations associated with the future retirement of tangible long‑lived assets in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long‑lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long‑lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long‑lived asset is depreciated over the estimated useful life of that asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk‑free rate and market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability.

Coal mines: We have asset retirement obligations for the final reclamation costs and post‑reclamation monitoring related to the Colowyo Mine, the New Horizon Mine, and the Fort Union Mine. The New Horizon Mine started final reclamation in June 2017.

Generation: We, including through our undivided interest in jointly owned facilities, have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the generating stations.

Aggregate carrying amounts of asset retirement obligations are as follows (dollars in thousands):

 

 

 

 

 

 

Nine Months Ended

 

 

 

September 30, 

 

 

    

2019

    

Asset retirement obligations at beginning of period

 

$

56,772

 

Liabilities incurred

 

 

9,900

 

Liabilities settled

 

 

(543)

 

Accretion expense

 

 

1,869

 

Change in cash flow estimate

 

 

286

 

Total asset retirement obligations at end of period

 

$

68,284

 

Less current asset retirement obligations at end of period

 

 

(2,294)

 

Long-term asset retirement obligations at end of period

 

$

65,990

 

 

The additional environmental reclamation obligation liability of $9.9 million was due to anticipated revision to the New Horizon mine reclamation plan to accommodate an alternative post mine land use as necessary for final mine reclamation. We continue to evaluate the New Horizon mine post reclamation obligation and will make adjustments to the obligation as needed.

 

We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which

12

sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.

 

The asset retirement obligations are determined in accordance with the accounting guidance and are different than the amount of any guarantees, or self-bonds for, reclamation obligations that are based upon state requirements.

 

NOTE 11 – OTHER DEFERRED CREDITS AND OTHER LIABILITIES

 

The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

    

2019

    

2018

 

Transmission easements

 

$

20,687

 

$

20,966

 

Operating lease liabilities - noncurrent

 

 

2,001

 

 

 —

 

Contract liabilities (unearned revenue) - noncurrent

 

 

4,311

 

 

4,592

 

Customer deposits

 

 

2,367

 

 

2,458

 

Other

 

 

19,562

 

 

22,250

 

Total other deferred credits and other liabilities

 

$

48,928

 

$

50,266

 

 

In 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $31.8 million will be paid by us for these easements from 2019 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $20.7 and $21.0 million as of September 30, 2019 and December 31, 2018, respectively, which are recorded as other deferred credits and other liabilities.

 

A lease liability represents a lessee’s obligation to make lease payments over the lease term. The long-term portion of our lease liabilities are included in other deferred credits and other liabilities and the current portion of our lease liabilities are included in current liabilities. See Note 15 – Leases.

 

A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in contract liabilities (unearned revenue) until recognized in other operating revenues over the life of the agreement. 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.

 

NOTE 12 – EMPLOYEE BENEFIT PLANS

 

Postretirement Benefits Other Than Pensions

 

We sponsor three medical plans for all non-bargaining unit employees under the age of 65. Two of the plans provide postretirement medical benefits to full-time non-bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55, and who elect to participate. All three of these non-bargaining unit medical plans offer postemployment medical benefits to employees on long-term disability. The plans were unfunded at September 30, 2019, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles.

 

13

The postretirement medical benefit and postemployment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

 

 

 

 

 

 

 

September 30, 

 

    

2019

Postretirement medical benefit obligation at beginning of period

 

$

8,556

Service cost

 

 

508

Interest cost

 

 

216

Benefit payments (net of contributions by participants)

 

 

(398)

Postretirement medical benefit obligation at end of period

 

$

8,882

Postemployment medical benefit obligation at end of period

 

 

371

Total postretirement and postemployment medical obligations at end of period

 

$

9,253

 

The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations.

 

In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the postretirement medical benefit obligation.

 

The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligations are included in accumulated other comprehensive income as follows (dollars in thousands):

 

 

 

 

 

 

 

September 30, 

 

    

2019

Amounts included in accumulated other comprehensive income at beginning of period

 

$

375

Amortization of prior service credit into other income

 

 

(59)

Amounts included in accumulated other comprehensive income at end of period

 

$

316

 

Defined Benefit Plans

 

We participate in the NRECA Pension Restoration Plan and the NRECA Executive Benefit Restoration Plan, both of which are intended to provide a supplemental benefit to the defined benefit plan for an eligible group of highly compensated employees. Eligible employees include the Chief Executive Officer and any other employees that become eligible. All our executive employees currently participate in one of the following pension restoration plans: the NRECA Pension Restoration Plan or the NRECA Executive Benefit Restoration Plan. Eligibility is determined annually and is based on January 1 base salary that exceeds the limits of the defined benefit plan. As of September 30, 2019, the executive benefit restoration obligation included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position was $0.7 million.

 

NOTE 13 – REVENUE

 

Revenue from Contracts with Customers

 

Our revenues are derived primarily from the sale of electric power to our Members pursuant to long-term wholesale electric service contracts. Our contracts with our Members extend through 2050 for 42 Members and 2040 for the remaining Member.

14

 

Member electric sales

 

Revenues from electric power sales to our Members are primarily from our Class A rate schedule. Our Class A rate schedule for electric power sales to our Members consist of three billing components: an energy rate and two demand rates. Our Class A rate schedule is variable and is approved by our Board. Energy and demand have the same pattern of transfer to our Members and are both measurements of the electric power provided to our Members. Therefore, the provision of electric power to our Members is one performance obligation. Prior to our Members’ requirement for electric power, we do not have a contractual right to consideration as we are not obligated to provide electric power until the Member requires each incremental unit of electric power. We transfer control of the electric power to our Members over time and our Members simultaneously receive and consume the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method, meter readings are taken at the end of each month for billing purposes, energy and demand are determined after the meter readings and Members are invoiced based on the meter reading. Payments from our Members are received in accordance with the wholesale electric service contracts’ terms, which is less than 30 days from the invoice date. Member electric sales revenue is recorded as Member electric sales on our consolidated statements of operations and Accounts receivable – Members on our consolidated statements of financial position.

 

In addition to our Member electric sales, we have non-member electric sales and other operating revenue which consist of several revenue streams. The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

2019

    

2018

 

 

2019

 

2018

Non-member electric sales:

    

 

 

 

 

 

 

 

 

 

 

 

Long-term contracts

 

$

12,647

 

$

11,985

 

$

35,241

 

$

34,457

Short-term contracts

 

 

15,692

 

 

19,019

 

 

36,602

 

 

28,468

Other

 

 

12,128

 

 

13,666

 

 

39,540

 

 

38,337

Total non-member electric sales and other operating revenue

 

$

40,467

 

$

44,670

 

$

111,383

 

$

101,262

 

Non-member electric sales

 

Revenues from electric power sales to non-members are primarily from long-term contracts and short-term market sales.

 

Prior to our customers’ demand for energy, we do not have a contractual right to consideration as we are not obligated to provide energy until the customer demands each incremental unit of energy. We transfer control of the energy to our customer over time and our customer simultaneously receives and consumes the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method. Payments are received in accordance with the contract terms, which is less than 30 days after the invoice is received by the customer.

 

Other operating revenue

 

Other operating revenue consists primarily of the following revenue streams: wheeling, transmission, supplying steam and water, leasing, and coal sales. Wheeling revenue is earned when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms which is within 20 days of the date the invoice was issued). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Steam and water revenue is derived from supplying steam and water to a paper

15

manufacturer located adjacent to the Escalante Generating Station (payments from the customer are received in accordance with the contract terms which is less than 15 days from the invoice date). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method. Lease revenue is primarily from a certain power sales arrangement that is required to be accounted for as an operating lease since the arrangement conveys the right to use power generating equipment for a stated period of time. 

Coal sales revenue results from the sale of coal from the Colowyo Mine to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered.

 

NOTE 14 – 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. However, in accordance with our regulatory accounting treatment, 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. Under this regulatory accounting approach, any income tax expense or benefit on our consolidated statements of operations includes only the current provision. Our consolidated statements of operations included an income tax benefit of $0.2 million for the nine months ended September 30, 2019 and $0.5 million for the comparable period in 2018. These income tax benefits are due to an alternative minimum tax credit refund.

 

NOTE 15 – LEASES

 

Leasing Arrangements As Lessee

 

We determine if an arrangement is a lease upon commencement of the contract. If an arrangement is determined to be a long-term lease (greater than 12 months), we recognize a right-of-use asset and lease liability based on the present value of the future minimum lease payments over the lease term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Our lease terms may also include options to extend or terminate the lease when it is reasonably certain that we will exercise those options. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Right-of-use assets are included in other deferred charges, the current portion of lease liabilities is included in current liabilities and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position.

 

We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as expense.

 

We have lease agreements as lessee for the right to use power generating equipment at the Brush Generating Station and for the use of various facilities and operational assets. Under the power purchase arrangement at the Brush Generating Station, we are required to account for the arrangement as an operating lease since it conveys to us the right to direct the use of 70 megawatts at the Brush Generating Station for a 10-year term ending December 31, 2019 and whereby we provide our own natural gas for generation of electricity. We do not anticipate renewing this power purchase arrangement.

 

Rent expense for all short-term and long-term operating leases was $1.8 million for the three months ended September 30, 2019 and $1.9 million for the comparable period in 2018. Rent expense for all short-term and long-term operating leases was $5.4 million for the nine months ended September 30, 2019 and $5.9 million for the comparable period in 2018. Rent expense is included in operating expenses on our consolidated statements of operations. As of September 30, 2019, there were no arrangements accounted for as finance leases.

 

16

Our consolidated statements of financial position include the following lease components (dollars in thousands):

 

 

 

 

 

September 30, 

 

2019

Operating leases

 

 

Operating lease right-of-use assets

$

7,941

Less: Accumulated amortization

 

(4,143)

  Net operating lease right-of-use assets

$

3,798

 

 

 

Operating lease liabilities - current

$

1,970

Operating lease liabilities - noncurrent

 

2,001

  Total operating lease liabilities

$

3,971

 

 

 

Operating leases

 

 

  Weighted average remaining lease term (years)

 

4.8

  Weighted average discount rate

 

5.58%

 

Future expected minimum lease commitments under operating leases are as follows (dollars in thousands):

 

 

 

 

 

Year 1

    

$

2,035

Year 2

 

 

509

Year 3

 

 

362

Year 4

 

 

280

Year 5

 

 

251

Thereafter

 

 

990

  Total lease payments

 

$

4,427

Less imputed interest

 

 

(456)

  Total

 

$

3,971

 

Leasing Arrangements As Lessor    

 

We have lease agreements as lessor for certain operational assets and had a lease agreement as lessor for power generating equipment at the J.M. Shafer Generating Station. Under the power sales arrangement at the J.M. Shafer Generating Station that expired on June 30, 2019, we were required to account for the arrangement as an operating lease since it conveyed to a third party the right to direct the use of 122 megawatts of the 272 megawatt generating capability of the J.M. Shafer Generating Station whereby the third party provided its own natural gas for generation of electricity. The revenue from these lease agreements of $1.6 million and $4.7 million for the three months ended September 30, 2019 and 2018, respectively, and $10.5 million and $13.5 million for the nine months ended September 30, 2019 and 2018, respectively, are included in other operating revenue on our consolidated statements of operations.

 

NOTE 16 – 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 measurement 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

17

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 are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities.

 

Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models, discounted cash flow models) for which all significant assumptions are observable in the market.

 

Level 3 inputs consist of unobservable market data which is 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 measured at fair value on a recurring basis with changes in fair value recognized in earnings. 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 cost and fair values of our marketable securities are as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of September 30, 2019

 

As of December 31, 2018

 

 

 

 

 

Estimated

 

 

 

Estimated

 

 

  

Cost

  

Fair Value

  

Cost

  

Fair Value

 

Marketable securities

  

$

594

  

$

582

  

$

818

  

$

712

 

 

Cash Equivalents

 

We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $92.2 million as of September 30, 2019 and $107.2 million as of December 31, 2018.

 

Debt

 

The fair values of debt were estimated using discounted cash flow analyses based on our current incremental borrowing 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 principal amounts and fair values of our debt are as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of September 30, 2019

 

As of December 31, 2018

 

 

 

Principal

 

Estimated

 

Principal

 

Estimated

 

 

  

Amount

  

Fair Value

  

Amount

  

Fair Value

 

Total debt

 

$

3,170,688

 

$

3,682,338

 

$

3,227,663

 

$

3,421,753

 

 

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NOTE 17 – 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”). The Owner Lessor is the owner of the Springerville Unit 3. We, as general partner of the Springerville Partnership, 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 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 Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville 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.    

 

Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31,

 

2019

    

2018

Net electric plant

 

$

780,945

 

$

794,549

Noncontrolling interest

 

$

110,602

 

$

110,169

Long-term debt

 

$

381,222

 

$

416,057

Accrued interest

 

$

4,420

 

$

12,056

 

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and nine months ended September 30, 2019 and 2018 (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine months ended

 

September 30, 

 

September 30, 

 

    

2019

    

2018

 

2019

 

2018

Depreciation, amortization and depletion

 

$

4,534

 

$

4,534

 

$

13,603

 

$

13,603

Interest

 

$

6,281

 

$

6,861

 

$

19,045

 

$

20,656

 

 

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. The net income or loss attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership is reflected on our consolidated statements of operations.

 

Unconsolidated Variable Interest Entities

 

Western Fuels Association, Inc. (“WFA”):  WFA is a non-profit membership corporation organized for the purpose of acquiring and supplying fuel resources to its members, which includes us. WFA, through its ownership in Western Fuels-Wyoming, supplies fuel to MBPP for the use at the Laramie River Station. We also receive coal supplies directly from WFA for the Escalante Generating Station in New Mexico. The pricing structure of the coal supply agreements

19

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 is not 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 $2.4 million at September 30, 2019 and December 31, 2018 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 Basin). 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 27.13 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 is not 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. Our investment in WFW, accounted for using the cost method, was $0.1 million at September 30, 2019 and December 31, 2018 and is included in investments in other associations.

 

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.  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 is not sufficient equity at risk for Trapper Mining to finance its activities without the additional financial support. Therefore, 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 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 September 30, 2019 and $15.4 million at December 31, 2018.

 

NOTE 18 – LEGAL

 

Other than as disclosed below, we do not expect any litigation or proceeding pending or threatened against us to have a potential material effect on our financial condition, results of operations or cash flows.

 

Pursuant to a long-term transmission agreement with another utility, such utility pays for and has firm rights to transfer power and energy across a transmission path in Colorado. Such right to payment and obligation to provide the transfer is borne equally by us and another entity. Due to the current capacity of the transmission path, such utility’s firm rights have been curtailed. The utility disputes its obligation to pay due to the current capacity of the transmission path and claims we, along with the other entity, are in breach of such transmission agreement. The utility has claimed damages caused by the alleged breach of approximately $6.9 million, plus interest, attorney fees, and any future damages. The other entity has filed a cross-claim against us claiming we are responsible for such entity’s share of any damages. The matter has been scheduled for arbitration commencing in January 2020. It is not possible to predict whether we will incur any liability in connection with this matter.

 

20

At our July 2019 Board meeting, our Board authorized us to take action to place us under wholesale rate regulation by FERC. On July 23, 2019, we filed with FERC our initial tariff, including our stated rate cost of service filing, market based rate authorization, and transmission Open Access Transmission Tariff. Our FERC tariff filing included our current Class A rate schedule for electric power sales to our Members as the wholesale rates payable by our Members.  On September 3, 2019, a membership agreement with a non-utility member became effective and we notified FERC of such and requested a partial waiver.  The admission of the new member that was not an electric cooperative or governmental entity resulted in us no longer being exempt from FERC wholesale rate regulation pursuant to the Federal Power Act. On October 4, 2019, FERC issued an order rejecting our filings without prejudice to us submitting a more complete set of filings that cure the deficiencies set forth in such order.  We expect to file with FERC a revised set of filings addressing the deficiencies set forth in FERC’s order before the end of 2019 and request a partial wavier. As a FERC-jurisdictional public utility currently making sales and provides services without satisfying the Federal Power Act’s filing obligations and FERC’s prior notice requirements, FERC may require us to refund to our customers certain amounts collected for the entire period that the rate was collected without FERC’s authorization, including Member and non-member electric sales and wheeling revenue.  FERC may also impose civil penalties. It is not possible to predict if FERC will require us to refund amounts to our customers or if FERC will impose civil penalties or to estimate any liability associated with such.

 

 

 

21

 

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 operating on a not-for-profit basis. We are organized for the purpose of providing electricity to our 43 member electric distribution systems known as our Class A members, or Members, that serve large portions of Colorado, Nebraska, New Mexico and Wyoming. We also sell a portion of our generated electric power to other utilities in our regions pursuant to long‑term contracts and short‑term sale arrangements. Our Members provide retail electric service to suburban and rural residences, farms and ranches, cities, towns and communities, as well as large and small businesses and industries.

 

We supply and transmit our Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long term purchase contracts and short term energy purchases. We own, lease, have undivided percentage interests in, have tolling arrangements or long-term purchase contracts with respect to, various generating facilities. Our diverse generation portfolio provides us with maximum available power of 4,419 megawatts, or MWs, of which approximately 1,059 MWs comes from renewables. In 2018, we estimate that nearly a third of the energy delivered by us and our Members to our Members’ customers came from non-carbon emitting resources. In December 2018, we executed a 100 MW solar-based power purchase agreement for the Spanish Peaks Solar Project that is expected to achieve commercial operation in 2023. In February 2019, we executed a 104 MW wind-based power purchase agreement for the Crossing Trails Wind Farm that is expected to achieve commercial operation in 2020. Upon commercial operation of these two renewable generating facilities, our renewable generation portfolio is expected to increase to 1,263 MWs.  In June 2019, we issued our sixth request for proposal for renewable energy resources. The 2019 request for proposal seeks projects of 10 MWs to 200 MWs with terms of 10 to 25 years.

 

We sold 13.8 million megawatt hours, or MWhs, for the nine months ended September 30, 2019, of which 89.6 percent was to Members. Total revenue from electric sales was $1.0 billion for the nine months ended September 30, 2019, of which 92.9 percent was from Member sales. Our results for the nine months ended September 30, 2019 were primarily impacted by seasonal weather changes.

·

Non-member electric sales increased by $8.9 million, or 14.2 percent, primarily due to increased short-term market sales and higher market pricing.

·

Fuel expense increased $36.2 million, or 21.5 percent, primarily due to greater generation from our generating facilities during the period.

·

Purchased power expense decreased $18.2 million, or 6.7 percent, primarily due to increased availability of Craig Generating Station Unit 3 and decreased demand for market purchases of power.

 

Our Bylaws and Wholesale Electric Service Contracts

Pursuant to our Bylaws, each Member is required to purchase from us the electric power and energy provided in the wholesale electric service contract with such Member. Our wholesale electric service contracts with our Members extending through 2050 for 42 Members (which constitute approximately 96.9 percent of our revenue from Member sales for the nine months ended September 30, 2019) and extending through 2040 for the remaining Member (Delta-Montrose Electric Association, or DMEA) are substantially similar. These contracts are subject to automatic extension thereafter until either party provides at least a two years’ 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 September 30, 2019, 21 Members have enrolled in this program with capacity totaling approximately 137 MWs of which 113 MWs are in operation.

Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board of Directors, or Board, may prescribe; provided, however, that no Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. From time to time, a Member may request equitable terms and conditions as our Board may prescribe for withdrawal or we may provide for informational purposes to all or a portion of our Members equitable

22

terms and conditions for withdrawal. In addition, from time to time, we may be in discussions with a Member regarding the equitable terms and conditions for withdrawal and their request for withdrawal, including granting a Member permission to explore options for potential alternative supplies of power known as shopping letters. However, any such permission is not considered authorization to withdraw and does not change the Member’s requirements and obligation to comply with such equitable terms and conditions as our Board may prescribe. As part of the contract committee considering alternative contracts with its Members, including partial requirements contracts, and the interaction with shopping letters and the make-whole number for a Member to meet all its contractual obligations to us, at our September 2019 Board meeting, our Board approved a temporary suspension of the policy and practice of providing its Members with make-whole numbers and shopping letters. The suspension is expected to continue until the contract committee has completed its work and provided recommendations to our Board, our Board has had an opportunity to consider and act upon such recommendations, and our Board has fully assessed the financial impacts of Member withdrawals and/or the offering of alternative contracts. At our September 2019 Board meeting, our Board also authorized the contract committee to consider alternative methods to determine the make-whole number with a goal of completing such work prior to our annual meeting in April 2020.

In July 2019, we reached a settlement with DMEA that provides for their withdrawal from us as permitted by our Bylaws, the resolution of all litigation with DMEA regarding various matters, the transfer of certain transmission assets to DMEA, and the payment to us of a withdrawal payment. The amount of the withdrawal payment was the product of the negotiated settlement with DMEA and is unique to DMEA because of the amounts associated with the transmission assets being transferred and patronage capital, and the date of withdrawal of DMEA from us. The specific terms of the settlement will be set forth in a withdrawal agreement and the parties are to cooperate to complete DMEA’s withdrawal effective May 1, 2020.

In November 2019, La Plata Electric Association, Inc., or LPEA, filed a formal complaint with the Colorado Public Utilities Commission, or COPUC, alleging that we have hindered LPEA’s ability to seek withdrawal from us. LPEA alleges, among other things, that our Board’s temporary suspension of providing Members with make-whole numbers is unlawful. LPEA seeks for the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the make-whole number.  We are evaluating the complaint filed by LPEA.

In November 2019, United Power, Inc., or United, filed a formal complaint with the COPUC alleging that we have hindered United’s ability to explore its power supply options by either withdrawing from us or continuing as a member under a partial requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory make-whole number. United seeks for the COPUC to issue an order establishing a make-whole number.  We are evaluating the complaint filed by United.

Responsible Energy Plan

In July 2019, we announced that we are pursuing a Responsible Energy Plan to transition to a cleaner generation portfolio while ensuring reliability, increasing Member flexibility and with a goal to lower wholesale rates to our Members. Our Responsible Energy Plan will set goals and pathways to:

·

comply with aggressive carbon reduction, renewable energy resource planning requirements

·

ensure the reliability and affordability of our wholesale power system, and

·

strive to lower wholesale rates to our Members while maintaining our strong financial position.

A key part of our approach is an engagement with former Colorado Governor Bill Ritter and the Center for the New Energy Economy at the Colorado State University to facilitate a collaborative stakeholder process for us that will contribute to and help define the Responsible Energy Plan. Our Members, through a contract committee, consisting of a representative from each Member, are currently considering greater contract flexibility for Members, including partial requirements contracts that would allow more local renewable energy projects. As part of the Responsible Energy Plan, we plan to address key issues including developing Western regional electricity markets, assisting impacted energy-producing communities, continuing and developing new tax incentives, addressing permitting for transmission line and generating facilities, and reconsidering the value of hydropower to ensure the Responsible Energy Plan’s success.

23

In September 2019, we announced, together with Basin Electric Power Cooperative and Western Area Power Administration, our decision to join Southwest Power Pool’s, or SPP, Western Energy Imbalance Service market.  SPP is expected to launch the Western Energy Imbalance Service market in February 2021. The market will centrally dispatch energy from these participants through the region every five minutes, and is expected to enhance both the reliability and affordability of electricity delivered from utilities to their customers.

In September 2019, we also announced that Nucla Generating Station, a 100-MW coal-fired generating facility in Western Colorado, was officially retired from service on September 19, 2019. Nucla Generating Station, which had been in a ready-to-run status, was to be retired by the end of 2022 as required by Colorado’s State Implementation Plan. In conjunction with the Board’s July 2019 action for early retirement of the Nucla Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation, we recognized an impairment loss of $37.1 million during the third quarter of 2019. Beginning in September 2019, the deferred impairment loss is being amortized to expense over the 3.3 year period ending in December 2022 and recovered from our Members in rates. We expect to begin dismantling the facility during the first half of 2020. To support the community through the transition, we plan to provide up to $0.5 million in community support spread across five years.

In October 2019, we announced that we are a founding member of the Beneficial Electrification League of Colorado, or BEL-CO, together with the Beneficial Electrification League, the National Rural Electric Cooperative Association, and the Natural Resource Defense Council.  Additional participants in launching BEL-CO include the Colorado Energy Office, the Colorado Rural Electric Association, and the Southwest Energy Efficiency Project.  Beneficial electrification promotes the efficient use of electricity to replace fossil fuels to benefit consumers, help improve the environment and provide a more robust and resilient energy system. Beneficial electrification is one of the central commitments of our Responsible Energy Plan, and the partnership that BEL-CO offers is one way for us and our Members to advance low-carbon technologies while helping consumers manage energy costs.

Critical Accounting Policies

The preparation of our financial statements in conformity with GAAP requires that our management make estimates and assumptions that affect the amounts reported in our consolidated financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. Except for the accounting policies for leases that were updated as a result of adopting the new lease standard on January 1, 2019, there were no material changes in our critical accounting policies as disclosed in our annual report on Form 10-K for the year ended December 31, 2018.

 

Factors Affecting Results

Master Indenture

 

As of September 30, 2019, we had approximately $2.8 billion of secured indebtedness outstanding under our indenture dated effective as of December 15, 1999, or Master Indenture, between us and Wells Fargo Bank, National Association, as trustee. Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under our Master Indenture. Our Master Indenture requires us to establish rates annually that are reasonably expected to achieve 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 historical and pro forma basis. Our Master Indenture also requires us to maintain an Equity to Capitalization Ratio (as defined in the Master Indenture) of at least 18 percent at the end of each fiscal year.

 

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 consolidated statements of operations. Net margins are treated as advances of capital by our members and are allocated to our Members on the basis

24

of revenue from electricity purchases from us and to our non-utility members as provided in their respective membership agreement. Net losses, should they occur, are not allocated to our members but are offset by future margins.

 

Our Board Policy for Financial Goals and Capital Credits, approved and subject to change by our Board, 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. On a periodic basis, our Board will determine whether to retire any patronage capital, and in what amounts, to our members. To date, we have retired approximately $355.5 million of patronage capital to our Members.

 

Pursuant to our Board Policy for Financial Goals and Capital Credits, we set rates to achieve a DSR and ECR in excess of the requirements under our Master Indenture in order to mitigate the risk of potential negative variances between budgeted margins and actual margins. This policy was revised in 2018 to establish a goal of our Board to either defer revenues and incomes as a regulatory liability or recognize previously deferred revenues and incomes in an amount that will result in a DSR equal to a DSR goal for the applicable year as set forth in the policy. As allowed by our Bylaws, the deferral or recognition of previously deferred revenues and income is for the purpose of stabilizing margins and limiting rate increases from year to year. In association with the above change, our Board Policy for Financial Goals and Capital Credits was also revised to provide that our Board will endeavor to fund an internally restricted cash account for the purpose of cash funding deferred revenues and incomes held as regulatory liabilities. The amount of cash our Board may internally restrict each year is not based upon the amount of revenue and income deferred. In connection with such policy, our Board has internally restricted cash in the amount of $14.8 million during the nine months ended September 30, 2019 for a total of $19.4 million as of September 30, 2019. Our Board may, at any time and for any reason, unrestrict any internally restricted cash.

 

Rates and Regulation

Our electric sales revenues are derived from electric power sales to our Members and non‑member purchasers.  Revenues from electric power sales to our Members are primarily from our Class A wholesale rate schedule. In 2018 and 2019, our Class A rate schedule (A-40) for electric power sales to our Members consist of three billing components: an energy rate and two demand rates. Member rates for energy and demand are set by our Board, and subject to Federal Energy Regulatory Commission’s, or FERC, approval, if applicable, consistent with the provision of reliable cost-based supply of electricity over the long term to our Members. The energy rate is billed based upon a price per kilowatt hour of physical electricity delivered to our Members without incorporating an on-peak and off-peak period. The two demand rates (a generation demand and a transmission/delivery demand) are billed on the Member’s highest thirty-minute integrated total demand measured in each monthly billing period during our peak period from noon to 10:00 pm daily, Monday through Saturday, with the exception of six holidays.

 

As approved by our Board in September 2019, the A-40 rate schedule will continue in effect for 2020, subject to FERC’s approval of our A-40 rate schedule. The average budgeted Member cents/kWh for 2020 will remain the same as 2019. For the third year in a row, our Class A wholesale rate schedule to our Members have remained unchanged.

 

At our July 2019 Board meeting, our Board authorized us to take action that will place us under wholesale rate regulation by FERC. In connection with such authorization, our Board, in accordance with our Bylaws, established a non-utility membership class and authorized entering into membership agreements with non-utility members.  On July 23, 2019, we filed with FERC our initial tariff, including our stated rate cost of service filing, market based rate authorization, and transmission Open Access Transmission Tariff. Our FERC tariff filing included our current Class A rate schedule (A-40) for electric power sales to our Members as the wholesale rates payable by our Members.  Numerous parties, including six of our Members, filed interventions or protests with FERC.  A number of interventions and comments in support were also filed with FERC, including letters of support from twenty-seven of our Members.

 

On September 3, 2019, a membership agreement with a non-utility member, MIECO, Inc., became effective and we notified FERC of such and requested a partial waiver.  The admission of the new member that was not an electric cooperative or governmental entity resulted in us no longer being exempt from FERC wholesale rate regulation pursuant to the Federal Power Act. The non-utility member, as set forth in the membership agreements, has the right to vote in our

25

annual membership meetings, has the right to patronage capital, and has the right to liquidation proceeds, but has no representation on our Board.

 

On October 4, 2019, FERC issued an order rejecting our filings without prejudice to us submitting a more complete set of filings that cure the deficiencies set forth in such order. The FERC order did not rule on any of the substantive issues raised by those that filed interventions or protests. We expect to file with FERC a revised set of filings addressing the deficiencies set forth in FERC’s order before the end of 2019.

 

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. However, in accordance with our regulatory accounting treatment, 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. Under this regulatory accounting approach, any income tax expense or benefit on our consolidated statements of operations includes only the current portion.

 

Results of Operations

General

Our electric sales revenues are derived from electric power sales to our Members and non‑member purchasers. See “– Factors Affecting Results – Rates and Regulation” for a description of our energy and demand rates to our Members. Long‑term contract sales to non‑members generally include energy and demand components. Short-term sales to non‑members are sold at market prices after consideration of incremental production costs. Demand billings to non‑members are typically billed per kilowatt of capacity reserved or committed to that customer.

Weather has a significant effect on the usage of electricity by impacting both the electricity used per hour and the total peak demand for electricity. Consequently, weather has a significant impact on our revenues and expenses. Relatively higher summer or lower winter temperatures tend to increase the usage of electricity for heating, air conditioning and irrigation. Mild weather generally reduces the usage of electricity because heating, air conditioning and irrigation systems are operated less frequently. The amount of precipitation during the growing season (generally May through September) also impacts irrigation use. Other factors affecting our Members’ usage of electricity include:

·

the amount, size and usage of machinery and electronic equipment;

·

the expansion of operations among our Members’ commercial and industrial customers;

·

the general growth or decline in service territory population; and

·

economic conditions.

 

26

Three months ended September 30, 2019 compared to three months ended September 30, 2018

Operating Revenues

Our operating revenues are primarily derived from electric power sales to our Members and non‑member purchasers. The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the three months ended September 30, 2019 and 2018 (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Period-to-period Change

 

2019

    

2018

 

Amount

    

Percent

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

Member electric sales

$

358,586

 

$

353,487

 

$

5,099

 

 

1.4%

Non-member electric sales

 

28,339

 

 

31,004

 

 

(2,665)

 

 

(8.6)%

Other

 

12,128

 

 

13,666

 

 

(1,538)

 

 

(11.3)%

Total operating revenues

$

399,053

 

$

398,157

 

$

896

 

 

0.2%

 

 

 

 

 

 

 

 

 

 

 

 

Energy sales to (in MWh):

 

 

 

 

 

 

 

 

 

 

 

Member electric sales

 

4,625,494

 

 

4,598,771

 

 

26,723

 

 

0.6%

Non-member electric sales

 

549,427

 

 

632,532

 

 

(83,105)

 

 

(13.1)%

 

 

5,174,921

 

 

5,231,303

 

 

(56,382)

 

 

(1.1)%

 

·

Member electric sales increased primarily due to greater Member energy needs because of warmer temperatures during the three months ended September 30, 2019 compared to the same period in 2018.

 

Operating Expenses

 

Our operating expenses are primarily comprised of the costs that we incur to supply and transmit our Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long-term purchase contracts and short-term energy purchases and the costs associated with any sales of power to non-members.

 

The following is a summary of the components of our operating expenses for the three months ended September 30, 2019 and 2018 (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Period-to-period Change

 

2019

    

2018

 

Amount

    

Percent

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

Purchased power

$

103,525

 

$

106,166

 

$

(2,641)

 

 

(2.5)%

Fuel

 

67,374

 

 

67,840

 

 

(466)

 

 

(0.7)%

Production

 

48,619

 

 

52,558

 

 

(3,939)

 

 

(7.5)%

Transmission

 

42,305

 

 

40,291

 

 

2,014

 

 

5.0%

General and administrative

 

12,978

 

 

6,398

 

 

6,580

 

 

102.8%

Depreciation, amortization and depletion

 

40,590

 

 

38,977

 

 

1,613

 

 

4.1%

Coal mining

 

1,675

 

 

637

 

 

1,038

 

 

163.0%

Other

 

4,640

 

 

3,897

 

 

743

 

 

19.1%

Total operating expenses

$

321,706

 

$

316,764

 

$

4,942

 

 

1.6%

 

·

Production expense decreased primarily due to decreased maintenance costs during the three months ended September 30, 2019 compared to the same period in 2018. Certain generating stations experienced maintenance

27

outages during the three months ended September 30, 2018 which resulted in increased maintenance costs compared to the same period in 2019.

·

General and administrative expense increased due to an increase in outside professional services as well as an overall increase in expenses related to general and administrative labor and benefits.

·

Coal mining expense increased due to the costs to provide coal from the Colowyo Mine to third parties during the three months ended September 30, 2019. There were minimal third party sales of coal from the Colowyo Mine during the same period in 2018.

 

Other Income

 

·

Other income increased $13.7 million, or 876.3 percent, to $14.3 million for the three months ended September 30, 2019 compared to $0.6 million for the same period in 2018. The increase was due to a $12.8 million retroactive royalty rate reduction granted to Colowyo Mine by the Office of Natural Resources Revenue. The decision reduces the royalty rate from 12.5 percent to 8 percent for coal extracted under certain leases from September 1, 2015 through June 30, 2019.

 

Nine months ended September 30, 2019 compared to nine months ended September 30, 2018

 

Operating Revenues

 

The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the nine months ended September 30, 2019 and 2018 (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 

 

Period-to-period Change

 

2019

    

2018

 

Amount

    

Percent

Operating revenues

 

 

 

 

 

 

 

 

 

 

 

Member electric sales

$

942,175

 

$

942,916

 

$

(741)

 

 

(0.1)%

Non-member electric sales

 

71,843

 

 

62,925

 

 

8,918

 

 

14.2%

Other

 

39,540

 

 

38,337

 

 

1,203

 

 

3.1%

Total operating revenues

$

1,053,558

 

$

1,044,178

 

$

9,380

 

 

0.9%

 

 

 

 

 

 

 

 

 

 

 

 

Energy sales to (in MWh):

 

 

 

 

 

 

 

 

 

 

 

Member electric sales

 

12,393,692

 

 

12,416,905

 

 

(23,213)

 

 

(0.2)%

Non-member electric sales

 

1,444,087

 

 

1,259,346

 

 

184,741

 

 

14.7%

 

 

13,837,779

 

 

13,676,251

 

 

161,528

 

 

1.2%

 

·

Non-member electric sales increased primarily due to increased short-term market sales and more favorable pricing. Short-term market sales increased 186,244 MWhs, or 44.9 percent, to 600,845 MWhs for the nine months ended September 30, 2019 compared to 414,601 MWhs for the same period in 2018. The average short-term market rate increased 4.8 percent for the nine months ended September 30, 2019 compared to the same period in 2018.

 

28

Operating Expenses

 

The following is a summary of the components of our operating expenses for the nine months ended September 30, 2019 and 2018 (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 

 

Period-to-period Change

 

2019

    

2018

 

Amount

    

Percent

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

Purchased power

$

252,948

 

$

271,187

 

$

(18,239)

 

 

(6.7)%

Fuel

 

204,271

 

 

168,081

 

 

36,190

 

 

21.5%

Production

 

148,457

 

 

165,750

 

 

(17,293)

 

 

(10.4)%

Transmission

 

122,329

 

 

122,255

 

 

74

 

 

0.1%

General and administrative

 

35,887

 

 

22,923

 

 

12,964

 

 

56.6%

Depreciation, amortization and depletion

 

116,879

 

 

118,620

 

 

(1,741)

 

 

(1.5)%

Coal mining

 

7,824

 

 

637

 

 

7,187

 

 

1128.3%

Other

 

12,154

 

 

11,317

 

 

837

 

 

7.4%

Total operating expenses

$

900,749

 

$

880,770

 

$

19,979

 

 

2.3%

 

·

Purchased power expense decreased primarily due to energy demands being met by increased generation from our generating facilities. Purchased power decreased (in MWhs) 10.5 percent for the nine months ended September 30, 2019 compared to the same period in 2018. This decrease was partially offset by a 4.3 percent increase in the average price of purchased power during the nine months ended September 30, 2019 compared to the same period in 2018.

·

Fuel expense increased due to greater generation from our generating facilities during the period. Net generation increased (in MWhs) 10.4 percent for the nine months ended September 30, 2019 compared to the same period in 2018. The increase in generation is primarily attributable to the availability of Craig Generating Station Unit 3 during the nine months ended September 30, 2019. Also included in fuel expense during the nine months ended September 30, 2019 is an additional environmental reclamation obligation of $9.9 million due to the anticipated revision to the New Horizon mine reclamation plan to accommodate an alternative post mine land use as necessary for final mine reclamation. We continue to evaluate the New Horizon mine post reclamation obligation and will make adjustments as needed.

·

Production expense decreased primarily due to decreased maintenance costs during the period. Certain generating stations experienced maintenance outages during the nine months ended September 30, 2018 which resulted in increased maintenance costs.

·

General and administrative expense increased primarily due to an increase in outside professional services as well as an overall increase in expenses related to general and administrative labor and benefits

·

Coal mining expense increased due to the costs to provide coal from the Colowyo Mine to third parties during the nine months ended September 30, 2019. There were minimal third party sales of coal from the Colowyo Mine during the same period in 2018.

 

Other Income

 

·

Other income increased $12.6 million, or 349.6 percent, to $16.2 million for the nine months ended September 30, 2019 compared to $3.6 million for the same period in 2018. The increase was due to a $12.8 million retroactive royalty rate reduction granted to Colowyo Mine by the Office of Natural Resources Revenue.

 

Financial condition as of September 30, 2019 compared to December 31, 2018

 

The principal changes in our financial condition from December 31, 2018 to September 30, 2019 were due to increases and decreases in the following:

 

29

Assets

 

·

Construction work in progress decreased $60.2 million, or 29.0 percent, to $147.5 million as of September 30, 2019 compared to $207.7 million as of December 31, 2018. The decrease was due to transfers to electric plant in service for completed projects of $168.9 million partially offset by capital expenditures of $108.7 million. The largest capital expenditures in construction work in progress include a turbine overhaul project at the J.M. Shafer Generating Station and various transmission improvements and system upgrades.

·

Other plant consists of mine assets and non-utility assets (which consist of piping and equipment specifically related to providing steam and water from the Escalante Generating Station to a third party for the use in the production of paper). Other plant increased $24.1 million, or 6.3 percent, to $408.8 million as of September 30, 2019 compared to $384.7 million as of December 31, 2018. The increase was primarily due to capital expenditures for the development of the Collom mining pit at the Colowyo Mine.

·

Restricted cash and investments-noncurrent increased $13.7 million, or 129.5 percent, to $24.3 million as of September 30, 2019 compared to $10.6 million as of December 31, 2018.  The increase was primarily due to restricting cash related to deferred revenues. Tri-State's Board has internally restricted cash in the amount of $19.4 million and $4.6 million as of September 30, 2019 and December 31, 2018, respectively.

·

Deposits and advances increased $13.2 million, or 44.4 percent, to $42.8 million as of September 30, 2019 compared to $29.6 million as of December 31, 2018. The increase was primarily due to prepayments of annual insurance, memberships and licenses. These prepayments are being amortized to expense over the term of the related insurance, membership or license period.

·

Regulatory assets increased $24.6 million, or 5.3 percent, to $462.0 million as of September 30, 2019 compared to $437.4 million as of December 31, 2018. The increase was primarily due to the deferral of the $37.1 million impairment loss related to the closure of the Nucla Station in September 2019. This increase was partially offset by $11.5 million of amortization of various regulatory assets to expense for recovery from our Members in rates.

 

Liabilities

 

·

Short-term borrowings increased $23.1 million, or 11.3 percent, to $227.2 million as of September 30, 2019 compared to $204.1 million as of December 31, 2018. Short-term borrowings consist of our commercial paper program that provides an additional financing source for our short-term liquidity needs. The increase was due to additional commercial paper issued between January 1, 2019 and September 30, 2019 to fund capital expenditures and working capital requirements.

·

Accrued interest increased $15.7 million, or 48.9 percent, to $47.8 million as of September 30, 2019 compared to $32.1 million as of December 31, 2018. The increase was due to accruals of $120.3 million for interest payments due in future periods partially offset by cash paid for interest of $104.6 million. Accrued interest as of September 30, 2019 is primarily comprised of the following amounts that are due during the fourth quarter of 2019: $16.2 million for the First Mortgage Obligation Series 2014B, $15.0 million for the First Mortgage Bonds Series 2010A, $10.5 million for the First Mortgage Bonds Series 2014E-1 and E-2, and $5.3 million for the First Mortgage Bonds Series 2016A.

·

Current maturities of long-term debt decreased $15.6 million, or 16.3 percent, to $80.2 million as of September 30, 2019 compared to $95.8 million as of December 31, 2018. The decrease was primarily due to a decrease of $27.1 million for the First Mortgage Obligations, Series 2009 principal payment that is due during the second quarter of 2020. This decrease was partially offset by an increase of $3.4 million for the Springerville certificates principal payment that is due during the first quarter of 2020 and an increase of $5.0 million for CFC debt that is due during the third quarter of 2020.

·

Regulatory liabilities decreased $9.0 million, or 6.5 percent, to $128.4 million as of September 30, 2019 compared to $137.4 million as of December 31, 2018. The decrease was primarily due to the June 2019 settlement of an interest rate swap. This interest rate swap was terminated with no associated debt issuance and no gain or loss was realized on our consolidated statements of operations.

·

Asset retirement obligations increased $11.4 million, or 20.9 percent, to $66.0 million as of September 30, 2019 compared to $54.6 million as of December 31, 2018. The increase was primarily due to an increased environmental reclamation obligation of $9.9 million for the anticipated revision to the New Horizon mine reclamation plan to accommodate an alternative post mine land use as necessary for final mine reclamation. We

30

continue to evaluate the New Horizon mine post reclamation obligation and will make adjustments to the obligation as needed.

 

Liquidity and Capital Resources

We finance our operations, working capital needs and capital expenditures from operating revenues and issuance of short-term and long-term borrowings. As of September 30, 2019, we had $95.9 million in cash and cash equivalents. Our committed credit arrangement as of September 30, 2019 is as follows (dollars in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Available

 

 

 

    

Authorized

 

    

September 30,

 

 

 

 

Amount

 

 

2019

 

 

2018 Revolving Credit Agreement

 

$

650,000

(1)

 

$

422,000

(2)

 

 

(1)

The amount of this facility that can be used to support commercial paper is limited to $500 million.

(2)

The portion of this facility that was unavailable at September 30, 2019 was $228 million which was dedicated to support outstanding commercial paper.

 

We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation, as lead arranger and administrative agent, in the amount of $650 million, or the 2018 Revolving Credit Agreement. The 2018 Revolving Credit Agreement includes a swingline sublimit of $100 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million, of which $100 million of the swingline sublimit, $75 million of the letter of credit sublimit, and $272 million of the commercial paper back-up sublimit remained available as of September 30, 2019. As of September 30, 2019, we had $422 million of availability under the 2018 Revolving Credit Agreement.

 

The 2018 Revolving Credit Agreement is secured under the Master Indenture and has a maturity date of April 25, 2023, unless extended as provided therein. Funds advanced under the 2018 Revolving Credit Agreement bear interest either at an adjusted LIBOR rate or an alternate base rate, at our option.  The adjusted LIBOR rate is the LIBOR rate for the term of the advance plus a margin (currently 1.00%) based on our credit ratings. The alternate base rate is the highest of (a) the federal funds rate plus ½ of 1.00%, (b) the prime rate, and (c) the one-month LIBOR rate plus 1.00% and plus a margin (currently 0%) based on our credit ratings. We had no outstanding borrowings at September 30, 2019.

 

The 2018 Revolving Credit Agreement contains customary representations, warranties, covenants, events of default and acceleration, including financial DSR and ECR requirements in line with the covenants contained in our Master Indenture. A violation of these covenants would result in the inability to borrow under the facility.

 

Under our commercial paper program, our Board authorized us to issue commercial paper in amounts that do not exceed the commercial paper back-up sublimit under our 2018 Revolving Credit Agreement, which was $500 million at September 30, 2019, thereby providing 100 percent dedicated support for any commercial paper outstanding. We had $228 million of commercial paper outstanding (prior to netting discounts) at September 30, 2019.

 

We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We are mindful of our debt and its maturities and we continually evaluate options to ensure that our balance sheet and capital structure is aligned with our business and the long-term health of our company.

 

We believe we have sufficient liquidity to fund operations and capital financing needs from projected cash on hand, our commercial paper program, and the 2018 Revolving Credit Agreement.

 

31

Cash Flow

Cash is provided by operating activities and issuance of debt. Capital expenditures and debt service payments comprise a significant use of cash.

 

Nine months ended September 30, 2019 compared to nine months ended September 30, 2018

 

Operating activities.  Net cash provided by operating activities was $201.9 million for the nine months ended September 30, 2019 compared to $138.4 million for the same period in 2018, an increase of $63.5 million. The increase in cash provided by operating activities was primarily impacted by a decrease in coal inventory (due to lower coal production tons at the Colowyo Mine), a decrease in other accounts receivable related to the settlement of insurance recoveries, an increase in cash collected from Member accounts receivable, and the timing of payment of accrued expenses.  

 

Investing activities.  Net cash used in investing activities was $155.6 million for the nine months ended September 30, 2019 compared to $200.7 million for the same period in 2018, a decrease of $45.1 million. The decrease was primarily due to lower capital expenditures in 2019 compared to the same period in 2018 for the development of the Collom mining pit at the Colowyo mine.

 

Financing activities.  Net cash used in financing activities was $53.5 million for the nine months ended September 30, 2019 compared to net cash provided by financing activities of $37.0 million for the same period in 2018, a decrease in cash provided by financing activities of $90.5 million. The decrease was primarily due to lower proceeds from issuance of long-term debt of $25.1 million, higher principal payments of long-term debt of $17.9 million (primarily for the Springerville certificates), a decrease in short-term borrowings of $38.5 million and higher patronage capital retirements to our Members of $6.2 million.

 

Capital Expenditures

We forecast our capital expenditures annually as part of our long-term planning. We regularly review these projections to update our calculations to reflect changes in our future plans, facility costs, market factors and other items affecting our forecasts.

 

Our actual capital expenditures depend on a variety of factors, including Member load growth, availability of necessary permits, regulatory changes, environmental requirements, construction delays and costs, and ability to access capital in credit markets. Thus, actual capital expenditures may vary significantly from our projections.

 

Capital projects include several transmission projects to improve reliability and load-serving capability throughout our service area and development of the Collom mining pit at the Colowyo Mine.

 

Contractual Commitments

Indebtedness.  As of September 30, 2019, we had $3.4 billion in outstanding obligations, including approximately $2.8 billion of debt outstanding secured on a parity basis under our Master Indenture, $228.0 million in short-term borrowings, one unsecured loan agreement totaling $28.9 million and the Springerville certificates totaling $371.2 million (which are secured only by a mortgage and lien on Springerville Unit 3 and the Springerville lease). Our debt secured by the lien of our Master Indenture includes notes payable to National Rural Utilities Cooperative Finance Corporation and CoBank, ACB (with the exception of one unsecured note), the First Mortgage Obligations, Series 2009C, the First Mortgage Bonds, Series 2010A, the First Mortgage Obligations, Series 2014B, the First Mortgage Bonds, Series 2014E-1 and E-2, First Mortgage Bonds, Series 2016A, First Mortgage Obligations, Series 2017A, pollution control revenue bonds, and amounts outstanding, if any, under the 2018 Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Master Indenture.

 

Operating Lease Obligations.  We have a 10-year power purchase agreement with AltaGas Brush Energy, Inc. to toll natural gas at the Brush Generating Station for 70 MWs, which ends on December 31, 2019. We account for this power

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purchase agreement as an operating lease because it conveys to us the right to use power generating equipment for a stated period of time.

 

Construction Obligations.  We have commitments to complete certain construction projects associated with improving the reliability of the generating facilities and the transmission system and the Collom pit at Colowyo Mine.

 

Coal Purchase Obligations.  We have commitments to purchase coal for our generating facilities under long-term contracts that expire between 2019 and 2034. These contracts require us to purchase a minimum quantity of coal at prices that are subject to escalation clauses that reflect cost increases incurred by the suppliers and market conditions.

 

Environmental Regulations and Litigation

We are subject to various federal, state and local laws, rules and regulations with regard to air quality, including greenhouse gases, water quality, and other environmental matters. These environmental laws, rules and regulations are

complex and change frequently. The following are recent developments relating to environmental regulations and litigation that may impact us.

 

New Mexico Renewable Portfolio Standards and Colorado Greenhouse Gas Regulation

 

The New Mexico Legislature in 2019 passed Senate Bill 489, the Energy Transition Act, which was signed into law by the New Mexico Governor on March 22, 2019. The legislation amends the existing renewable energy standards, or RPS, that requires our New Mexico Members to obtain a percentage of their energy requirements from renewable sources. The legislation adds requirements for our New Mexico Members to obtain 40 percent renewable energy by 2025 and 50 percent renewable energy by 2030, and adds a target of achieving a zero carbon resource standard by 2050, with at least 80 percent renewable energy. The legislation includes regulatory relief for the 2050 target, if implementing the provisions of the bill are not technically feasible, hampers reliability or increases cost of electricity to unaffordable levels.

 

The Colorado General Assembly in 2019 passed House Bill 19-1261, Climate Action Plan to Reduce Pollution, which was signed by the Colorado Governor on May 30, 2019. The legislation requires that the Air Quality Control Commission develop rules to reduce statewide greenhouse gas emissions 26 percent by 2025, 50 percent by 2030, and 90 percent by 2050, relative to 2005 emissions.

 

The New Mexico and Colorado legislation is expected to have a material impact on our operations and our future generation portfolio; however until the final rules are enacted that implement the respective legislation, it is not yet possible to estimate the impacts on our operations or future generation portfolio.  The impacts could include modifications to the design or operation of existing facilities, increases in our operating expenses and potential stranded costs, investments in new generation and transmission, and decreases in operations or closure of our fossil fuel generating facilities or coal mines prior to their current depreciable or depletable lives.

 

Collom Air Permit

 

On July 25, 2018, the Center for Biological Diversity and Sierra Club filed a complaint against the Colorado Department of Public Health and Environment, or CDPHE, in opposition to CDPHE’s issuance of an air permit for construction and operation of the Collom pit at the Colowyo Mine. We and Colowyo Coal Company LP on August 23, 2018 filed an unopposed motion to intervene and answer to the complaint. The CDPHE on September 4, 2018 filed an answer and defenses to the complaint. On February 14, 2019, the court issued a stay of the case proceedings until May 1, 2019, while CDPHE processes a permit revision. As the permit revision was still pending on April 30, 2019, we filed a Motion for Stay Extension. On May 21, 2019, the Center for Biological Diversity and Sierra Club filed an Opposition to Motion for Stay Extension. On May 28, 2019, the court granted our motion to extend the stay until October 29, 2019. The court order requires parties to file a Joint Status Report by October 8, 2019. The parties filed such Joint Status Report by October 8, 2019. On August 13, 2019, CDPHE issued the public notice for commenting on the revision to the air permit. The 60-day public comment period began on August 14, 2019 and ended on October 12, 2019. We filed selective comments on October 11, 2019. The final air permit revision was issued by CDPHE on November 7, 2019.

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Affordable Clean Energy Rule

 

On July 8, 2019, the Environmental Protection Agency, or EPA, published the final Affordable Clean Energy rule, or ACE Rule, to repeal and replace the Clean Power Plan, or CPP. Implementation of the CPP has been stayed by the United States Supreme Court since 2016. The ACE Rule requires states to develop unit-specific carbon dioxide emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to us will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time. It is too early to know how each state in which we operate will administer the ACE Rule. If a state implements a very strict interpretation of the rule, it may have a material impact on our operations.

 

For further discussion regarding potential effects on our business from environmental regulations, see “Item 1 – BUSINESS — ENVIRONMENTAL REGULATION” and “Item 1A — RISK FACTORS” in our annual report on Form 10-K for the year ended December 31, 2018.

 

COPUC Electric Resource Planning Rules

 

The Colorado General Assembly in 2019 passed legislation that revises processes undertaken by the COPUC. Senate Bill 19-236, Sunset Public Utilities Commission, which was signed by the Colorado Governor on May 30, 2019, continues the COPUC for seven years. Among other provisions, the bill requires us to file and obtain COPUC approval for integrated or electric resource plans and directs the COPUC to require electric public utilities to consider the cost of carbon dioxide emissions in certain proceedings. On July 31, 2019, the COPUC opened a rulemaking pursuant to Senate Bill 19-236 proposing electric resource planning rules applicable to us. We, along with two Members and others, filed initial comments on September 11, 2019. We, along with others, also filed reply comments on September 25, 2019. The COPUC held an en banc hearing on the proposed rule on October 15, 2019. The proposed rule would apply a similar “Phase I/Phase II” electric resource planning process to us as currently applies to Colorado’s investor owned utilities. The bill and final rules could have a material impact on our operations and our future generation portfolio; however, until the final rules are enacted that implement the bill, it is not yet possible to estimate the impacts on our operations or future generation portfolio.

 

Rating Triggers

Our current senior secured ratings are “A3 (stable outlook)” by Moody’s Investors Services, or Moody’s, “A (stable outlook)” by Standard & Poor’s Global Ratings, or S&P, and “A (negative outlook)” by Fitch Rating Inc., or Fitch. Our current short-term ratings are “P‑2” by Moody’s, “A‑1” by S&P, and “F1+” by Fitch.

 

Our 2018 Revolving Credit Agreement includes a pricing grid related to the LIBOR spread, commitment fee and letter of credit fees due under the facility. A downgrade of our senior secured ratings could result in an increase in each of these pricing components. We do not believe that any such increase would be significant or have a material adverse effect on our financial condition or our future results of operations.

 

We currently have contracts that require adequate assurance of performance. These include natural gas supply contracts, coal purchase contracts, and financial risk management contracts. Some of the contracts are directly tied to our credit rating generally being maintained at or above investment grade by S&P and Moody’s. We may enter into additional contracts which may contain similar adequate assurance requirements. If we are required to provide such adequate assurances, we do not believe the amounts will be significant or that they will have a material adverse effect on our financial condition or our future results of operations.

 

Off Balance Sheet Arrangements

We have no off-balance sheet arrangements.

 

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

There have been no material changes to market risks during the most recent fiscal quarter from those reported in our annual report on Form 10-K for the year ended December 31, 2018.  

 

Item 4.  Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

As of the end of the period covered by this report, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

 

Changes in Internal Controls

 

There have been no changes in our internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

 

PART II.  OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

Other than as disclosed below, there have been no material changes from the legal proceedings disclosed in “Item 3 – LEGAL PROCEEDINGS” in our annual report on Form 10-K for the year ended December 31, 2018.

 

Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. DMEA, which constituted approximately 3.1 percent of our revenue from Member sales for the nine months ended September 30, 2019, requested an exit cost calculation from us and we provided to DMEA a calculation of potential terms for withdrawal. On December 6, 2018, DMEA filed a formal complaint with the COPUC alleging the COPUC has jurisdiction over the equitable terms and conditions as our Board may prescribe for withdrawal and that the calculation of the potential buyout terms provided to DMEA was unjust, unreasonable, and discriminatory. On July 19, 2019, we signed a settlement agreement with DMEA that provides for their withdrawal from us as permitted by our Bylaws, the resolution of all litigation with DMEA regarding various matters, the transfer of certain transmission assets to DMEA, and the payment to us of a withdrawal payment. The amount of the withdrawal payment was the product of the negotiated settlement with DMEA and is unique to DMEA because of the amounts associated with the transmission assets being transferred and patronage capital, and the date of withdrawal of DMEA from us. The specific terms of the settlement will be set forth in a withdrawal agreement and the parties are to cooperate to complete DMEA’s withdrawal effective May 1, 2020. On July 19, 2019, the parties also filed a stipulation to dismiss DMEA’s formal complaint with the COPUC. On August 14, 2019, the COPUC adopted an order closing the proceeding.

 

On November 5, 2019, LPEA filed a formal complaint with the COPUC alleging that we have hindered LPEA’s ability to seek withdrawal from us. LPEA alleges, among other things, that our Board’s temporary suspension of providing Members with make-whole numbers is unlawful. LPEA seeks the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the make-whole number.  We are evaluating the complaint filed by LPEA. LPEA constitutes approximately 5.5 percent of our revenue from Member sales for the nine months ended September 30, 2019.

 

On November 6, 2019, United filed a formal complaint with the COPUC alleging that we have hindered United’s ability to explore its power supply options by either withdrawing from us or continuing as a member under a partial

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requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory make-whole number. United seeks for the COPUC to issue an order establishing a make-whole number.  We are evaluating the complaint filed by United. United constitutes approximately 16.3 percent of our revenue from Member sales for the nine months ended September 30, 2019.

 

 

Item 1A.  Risk Factors

 

We are currently operating as a FERC-jurisdictional public utility making sales and providing services without satisfying the Federal Power Act’s filing obligations and FERC’s prior notice requirement.  As a result, we may be subject to certain penalties, fines and/or refunds.

 

As a FERC-jurisdictional public utility currently making sales and providing services without satisfying the Federal Power Act’s filing obligations and FERC’s prior notice requirements, FERC may require us to refund to our customers certain amounts collected for the entire period that the rate was collected without FERC’s authorization, including Member and non-member electric sales and wheeling revenue.  FERC may also impose civil penalties. It is not possible to predict if FERC will require us to refund amounts to our customers or if FERC will impose civil penalties or to estimate any liability associated with such. In addition, our customers may dispute their obligation to pay us or pay under protest because we do not have FERC approved rates.

 

Although we expect that our revised filings with FERC will cure the deficiencies set forth FERC’s rejection of our initial filing, there is no guarantee that FERC will accept our revised filing or that FERC will accept our revised filing subject to refund.

 

On October 4, 2019, FERC issued an order rejecting our initial filings without prejudice to us submitting a more complete set of filings that cure the deficiencies set forth in such order.  We expect to file with FERC a revised set of filings before the end of 2019.  However, there can be no guarantee that FERC will accept our revised filings.  If FERC rejects our revised filing, our future business plans may be impacted.  If FERC accepts our filing subject to refund, we may be required to accrue certain liabilities associated with the amounts subject to refund and may be required to refund certain revenue collected.

 

 

Item 4.  Mine Safety Disclosures

 

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this quarterly report on Form 10-Q.

 

Item 6.  Exhibits

 

 

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

 

 

 

 

 

Tri-State Generation and Transmission
Association, Inc.

 

 

 

 

Date: November 13, 2019

 

By:

   /s/ Duane Highley

 

 

 

Duane Highley

 

 

 

Chief Executive Officer

 

 

 

 

 

 

 

 

Date: November 13, 2019

 

 

   /s/ Patrick L. Bridges

 

 

 

Patrick L. Bridges

 

 

 

Senior Vice President/Chief Financial Officer (Principal Financial Officer)

 

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