10-Q 1 tris-20200930x10q.htm 10-Q

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, 2020

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, 2020

    

Page Number

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Consolidated Statements of Financial Position as of September 30, 2020 (unaudited) and December 31, 2019

1

Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2020 and 2019 (unaudited)

2

Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2020 and 2019 (unaudited)

3

Consolidated Statements of Equity — Three and Nine Months Ended September 30, 2020 and 2019 (unaudited)

4

Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2020 and 2019 (unaudited)

5

Notes to Unaudited Consolidated Financial Statements For the Three and Nine Months Ended September 30, 2020 and 2019

6

Item 2.

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

25

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

38

Item 4.

Controls and Procedures

38

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

38

Item 4.

Mine Safety Disclosures

40

Item 6.

Exhibits

40

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, operation, or closure 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, 2020

    

December 31, 2019

 

ASSETS

(unaudited)

Property, plant and equipment

Electric plant

In service

$

6,184,657

$

6,090,392

Construction work in progress

 

130,651

 

164,924

Total electric plant

 

6,315,308

 

6,255,316

Less allowances for depreciation and amortization

 

(2,975,735)

 

(2,641,470)

Net electric plant

 

3,339,573

 

3,613,846

Other plant

 

415,015

 

409,051

Less allowances for depreciation, amortization and depletion

 

(133,587)

 

(113,607)

Net other plant

 

281,428

 

295,444

Total property, plant and equipment

 

3,621,001

 

3,909,290

Other assets and investments

Investments in other associations

 

159,187

 

161,945

Investments in and advances to coal mines

 

19,558

 

19,681

Restricted cash and investments

 

4,887

 

30,516

Other noncurrent assets

 

8,825

 

8,654

Total other assets and investments

 

192,457

 

220,796

Current assets

Cash and cash equivalents

 

164,965

 

83,070

Restricted cash and investments

 

199

 

182

Deposits and advances

 

31,586

 

28,434

Accounts receivable—Utility Members

 

99,420

 

105,371

Other accounts receivable

 

25,198

 

28,039

Coal inventory

 

55,879

 

50,191

Materials and supplies

 

93,342

 

93,632

Total current assets

 

470,589

 

388,919

Deferred charges

Regulatory assets

 

717,177

 

497,279

Prepayment—NRECA Retirement Security Plan

 

22,833

 

26,862

Other

 

58,670

 

42,672

Total deferred charges

 

798,680

 

566,813

Total assets

$

5,082,727

$

5,085,818

EQUITY AND LIABILITIES

Capitalization

Patronage capital equity

$

1,029,050

$

1,031,063

Accumulated other comprehensive loss

 

(7,604)

 

(1,518)

Noncontrolling interest

 

113,425

 

111,717

Total equity

 

1,134,871

 

1,141,262

Long-term debt

 

3,205,904

 

3,063,351

Total capitalization

 

4,340,775

 

4,204,613

Current liabilities

Utility Member advances

 

16,504

 

18,025

Accounts payable

 

105,786

 

99,033

Short-term borrowings

252,323

Accrued expenses

 

29,165

 

43,761

Current asset retirement obligations

2,840

2,460

Accrued interest

 

45,830

 

29,716

Accrued property taxes

 

28,086

 

29,129

Current maturities of long-term debt

 

87,178

 

81,555

Total current liabilities

 

315,389

 

556,002

Deferred credits and other liabilities

Regulatory liabilities

 

237,187

 

122,169

Deferred income tax liability

 

33,744

 

58,937

Asset retirement and environmental reclamation obligations

 

80,303

 

76,454

Other

 

56,477

 

56,399

Total deferred credits and other liabilities

 

407,711

 

313,959

Accumulated postretirement benefit and postemployment obligations

 

18,852

 

11,244

Total equity and liabilities

$

5,082,727

$

5,085,818

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, 

    

2020

    

2019

    

2020

    

2019

    

Operating revenues

Utility Member electric sales

$

346,769

$

358,586

$

926,529

$

942,175

Non-member electric sales

 

38,606

 

28,339

 

71,044

 

71,843

Other

 

16,226

 

12,128

 

37,150

 

39,540

 

401,601

 

399,053

 

1,034,723

 

1,053,558

Operating expenses

Purchased power

 

103,136

 

103,525

 

260,804

 

252,948

Fuel

 

65,061

 

67,374

 

165,679

 

204,271

Production

 

39,698

 

48,619

 

122,595

 

148,457

Transmission

 

43,989

 

42,305

 

127,175

 

122,329

General and administrative

 

17,081

 

12,978

 

49,337

 

35,887

Depreciation, amortization and depletion

 

45,775

 

40,590

 

137,110

 

116,879

Coal mining

 

4,200

 

1,675

 

8,021

 

7,824

Other

 

2,691

 

4,640

 

13,429

 

12,154

 

321,631

 

321,706

 

884,150

 

900,749

Operating margins

 

79,970

 

77,347

 

150,573

 

152,809

Other income

Interest

 

959

 

1,364

 

3,248

 

4,156

Capital credits from cooperatives

 

1,186

 

1,186

 

4,674

 

4,520

Other income (expense)

 

197

 

14,314

 

348

 

16,226

 

2,342

 

16,864

 

8,270

 

24,902

Interest expense

 

 

 

Interest

37,673

39,991

114,533

120,754

Interest charged during construction

(1,460)

(1,961)

(5,022)

(6,800)

36,213

38,030

109,511

113,954

Income tax benefit

 

(154)

 

(77)

 

(484)

 

(231)

Net margins including noncontrolling interest

 

46,253

 

56,258

 

49,816

 

63,988

Net margin attributable to noncontrolling interest

 

(1,424)

 

(1,113)

 

(4,164)

 

(3,239)

Net margins attributable to the Association

$

44,829

$

55,145

$

45,652

$

60,749

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, 

    

2020

    

2019

    

2020

    

2019

    

Net margins including noncontrolling interest

$

46,253

$

56,258

$

49,816

$

63,988

Other comprehensive loss:

Amortization of actuarial loss on postretirement benefit obligation included in net margin

177

 

(10)

1,287

 

13

Unrecognized prior service cost

(7,373)

(214)

Other comprehensive loss

177

 

(10)

(6,086)

 

(201)

Comprehensive income including noncontrolling interest

46,430

 

56,248

43,730

 

63,787

Net comprehensive income attributable to noncontrolling interest

(1,424)

 

(1,113)

(4,164)

 

(3,239)

Comprehensive income attributable to the Association

$

45,006

$

55,135

$

39,566

$

60,548

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, 

    

2020

    

2019

    

    

2020

    

2019

    

Patronage capital equity at beginning of period

$

984,221

$

1,021,358

$

1,031,063

$

1,015,754

Net margins attributable to the Association

 

44,829

 

55,145

 

45,652

 

60,749

Retirement of patronage capital

(47,665)

Patronage capital equity at end of period

 

1,029,050

 

1,076,503

 

1,029,050

 

1,076,503

Accumulated other comprehensive income (loss) at beginning of period

 

(7,781)

 

184

 

(1,518)

 

375

Amortization of prior service cost

177

(10)

1,287

13

Unrecognized prior service cost

 

 

 

(7,373)

 

(214)

Accumulated other comprehensive income (loss) at end of period

(7,604)

 

174

(7,604)

 

174

Noncontrolling interest at beginning of period

 

113,189

 

110,841

 

111,717

 

110,169

Net comprehensive income attributable to noncontrolling interest

 

1,424

 

1,113

 

4,164

 

3,239

Equity distribution to noncontrolling interest

(1,188)

 

(1,352)

(2,456)

 

(2,806)

Noncontrolling interest at end of period

 

113,425

 

110,602

 

113,425

 

110,602

Total equity at end of period

$

1,134,871

$

1,187,279

$

1,134,871

$

1,187,279

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, 

  

2020

  

2019

    

Operating activities

Net margins including noncontrolling interest

$

49,816

$

63,988

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

Depreciation, amortization and depletion

137,110

 

116,879

Amortization of intangible asset

 

 

3,662

Amortization of NRECA Retirement Security Plan prepayment

 

4,029

 

4,029

Amortization of debt issuance costs

1,832

 

1,773

Impairment loss

259,761

37,067

Deferred impairment loss and other closure costs

(268,163)

(37,067)

Deferred membership withdrawal income

110,165

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

2,813

 

(486)

Changes in operating assets and liabilities:

Accounts receivable

5,844

 

(155)

Coal inventory

(5,688)

 

3,922

Materials and supplies

290

 

(2,943)

Accounts payable and accrued expenses

9,337

 

3,418

Accrued interest

16,113

 

15,691

Accrued property taxes

(1,043)

 

(282)

Other

(16,323)

 

(7,581)

Net cash provided by operating activities

305,893

 

201,915

Investing activities

Purchases of plant

(100,821)

 

(149,396)

Sale of electric plant

26,000

Changes in deferred charges

(4,532)

 

(6,277)

Proceeds from other investments

68

 

65

Net cash used in investing activities

(79,285)

 

(155,608)

Financing activities

Changes in Utility Member advances

(1,520)

 

(5,351)

Payments of long-term debt

(277,119)

 

(91,884)

Proceeds from issuance of long-term debt

425,000

 

34,910

Debt issuance costs

(637)

(13)

Increase (decrease) in short-term borrowings, net

(252,323)

23,036

Retirement of patronage capital

 

(60,991)

 

(11,101)

Equity distribution to noncontrolling interest

(2,456)

(2,806)

Other

(279)

(257)

Net cash used in financing activities

(170,325)

 

(53,466)

Net increase (decrease) in cash, cash equivalents and restricted cash and investments

56,283

 

(7,159)

Cash, cash equivalents and restricted cash and investments – beginning

113,768

 

127,590

Cash, cash equivalents and restricted cash and investments – ending

$

170,051

$

120,431

Supplemental cash flow information:

Cash paid for interest

$

97,218

$

103,782

Cash paid for income taxes

$

$

Supplemental disclosure of noncash investing and financing activities:

Change in plant expenditures included in accounts payable

$

2,217

$

(873)

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, 2020 and 2019

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, 2019 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, 2020, results of operations for the three and nine months ended September 30, 2020 and 2019, and cash flows for the nine months ended September 30, 2020 and 2019 are not necessarily indicative of the results that may be expected for an entire year or any other period.

Basis of Consolidation

We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis serving large portions of Colorado, Nebraska, New Mexico and Wyoming. We were incorporated under the laws of the State of Colorado in 1952. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. We have forty-two electric distribution member systems who are Class A members (“Class A Member(s)”) to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A Members and any Class B members are collectively referred to as our “Utility Members.” Our Class A Members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” The addition of Non-Utility Members in 2019 and specifically the addition of MIECO, Inc. on September 3, 2019 removed the exemption from the Federal Energy Regulatory Commission’s (“FERC”) regulation for us, thus subjecting us to full rate and transmission jurisdiction by FERC effective September 3, 2019. Our stated rate to our Class A Members was filed at FERC on December 23, 2019 and was accepted by FERC on March 20, 2020.

We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with GAAP, the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.

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 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, 2020 (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

%  

$

395,099

$

249,804

$

334

MBPP - Laramie River Station

27.13

%

 

489,147

 

301,561

 

5,075

Total

$

884,246

$

551,365

$

5,409

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 based on regulatory orders or other available evidence, it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs that we expect to recover from our Utility 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 Utility Members based on rates approved by the applicable authority. 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, including the use of regulatory assets and liabilities, is now subject to FERC approval. Expected recovery of deferred costs and returning deferred credits are based on specific ratemaking decisions by FERC or precedent for each item. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery through rates.

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

September 30, 

December 31,

 

    

2020

    

2019

 

Regulatory assets

Deferred income tax expense (1)

$

33,744

$

58,937

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

 

81,996

 

83,714

Goodwill – J.M. Shafer (3)

 

47,008

 

49,145

Goodwill – Colowyo Coal (4)

 

36,419

 

37,194

Deferred debt prepayment transaction costs (5)

 

134,459

 

140,931

Deferred Holcomb expansion impairment loss (6)

89,988

93,494

Unrecovered plant (7)

 

293,563

 

33,864

Total regulatory assets

717,177

497,279

 

Regulatory liabilities

Interest rate swap - realized gain (8)

 

3,391

 

3,744

Deferred revenues (9)

 

75,853

 

75,853

Membership withdrawal (10)

157,943

42,572

Total regulatory liabilities

237,187

122,169

Net regulatory asset

$

479,990

$

375,110

(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 Utility Members through rates.

7


(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 Utility Members through rates.
(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 Utility Members through 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 Utility Members through 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 being amortized to depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates.
(7)Represents deferral of the impairment losses related to the early retirement of the Nucla and Escalante Generating Stations. In July 2019, our 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 of the Nucla Generating Station, 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 for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. In January 2020, our Board approved the early retirement of the Escalante 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 $268.2 million during the first quarter of 2020. The deferred impairment loss for Escalante Generating Station will be amortized to depreciation, amortization and depletion expense beginning in 2021 through the end of 2045, which was the depreciable life of Escalante Generating Station, and is expected to be recovered from our Utility Members through rates. The annual amortization is expected to approximate the former annual Escalante Generating Station depreciation for the remaining life of the asset.
(8)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 Utility Members through reduced rates when recognized in future periods.
(9)Represents deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members through reduced rates when recognized in non-member electric sales revenue in future periods.
(10)Represents the deferral of the recognition of other income related to the June 30, 2016 withdrawal of a former Utility Member from membership in us and the June 30, 2020 withdrawal of Delta-Montrose Electric Association (“DMEA”) from membership in us. In connection with the DMEA withdrawal, we recognized $110.2 million of other income and $5.2 million of gain on sale of assets which was subsequently deferred. The total deferred membership withdrawal income will be refunded to Utility Members through reduced rates, subject to FERC approval, 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.

8


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

September 30, 

December 31, 

    

2020

    

2019

 

Basin Electric Power Cooperative

$

114,036

$

117,368

National Rural Utilities Cooperative Finance Corporation - patronage capital

 

11,933

 

11,761

National Rural Utilities Cooperative Finance Corporation - capital term certificates

15,885

15,953

CoBank, ACB

 

11,141

 

10,201

Western Fuels Association, Inc.

 

2,302

 

2,409

Other

 

3,890

 

4,253

Investments in other associations

$

159,187

$

161,945

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, 2020 or during 2019.

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,

    

2020

    

2019

 

Investment in Trapper Mine

$

16,279

$

15,881

Advances to Dry Fork Mine

 

3,279

 

3,800

Investments in and advances to coal mines

$

19,558

$

19,681

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.

9


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,

 

    

2020

    

2019

 

Cash and cash equivalents

$

164,965

$

83,070

Restricted cash and investments - current

 

199

 

182

Restricted cash and investments - noncurrent

4,887

30,516

Cash, cash equivalents and restricted cash and investments

$

170,051

$

113,768

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 internally restricted cash in the amount of $25.5 million as of December 31, 2019 which was included in restricted cash and investments - noncurrent. Our Board may, at any time and for any reason, unrestrict any internally restricted cash. On March 10, 2020, our Board took action to unrestrict the $25.5 million balance of the restricted cash in response to volatile market conditions.

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, 2020, we recognized $0.9 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, 

  

2020

    

2019

    

Accounts receivable - Utility Members

$

99,420

$

105,371

Other accounts receivable - trade:

Non-member electric sales

7,900

4,727

Other

16,615

20,628

Total other accounts receivable - trade

24,515

25,355

Other accounts receivable - nontrade

683

2,684

Total other accounts receivable

$

25,198

$

28,039

Contract liabilities (unearned revenue)

$

6,281

$

7,041

10


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, 

 

    

2020

    

2019

 

Preliminary surveys and investigations

$

23,012

$

21,261

Advances to operating agents of jointly owned facilities

 

8,686

 

3,917

Operating lease right-of-use assets

10,086

7,622

Other

 

16,886

 

9,872

Total other deferred charges

$

58,670

$

42,672

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 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 or the expense could be deferred as a regulatory asset to be recovered from our Utility Members through rates subject to approval by our Board and FERC.

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.

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 $3.2 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 $21.5 million as of September 30, 2020. 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 on an annual basis and an equity to capitalization ratio requirement of at least 18 percent at the end of each fiscal year. Other than the Springerville certificates that has a debt service ratio requirement of at least 1.02 on an annual basis, all other long-term debt contains a debt service ratio requirement of at least 1.10 on an annual basis.

We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation (“CFC”), as lead arranger and administrative agent, in the amount of $650 million (“Revolving Credit Agreement”) that expires on April 25, 2023 and 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. As of September 30, 2020, we had $650.0 million in availability under the Revolving Credit Agreement.

11


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

September 30, 

December 31, 

 

    

2020

  

2019

 

Total debt

$

3,314,353

3,166,472

Less debt issuance costs

(26,218)

(27,412)

Less debt discounts

(9,722)

(9,906)

Plus debt premiums

14,669

15,752

Total debt adjusted for debt issuance costs, discounts and premiums

3,293,082

3,144,906

Less current maturities

 

(87,178)

 

(81,555)

Long-term debt

$

3,205,904

$

3,063,351

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 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 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.

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

September 30, 

December 31, 

 

    

2020

    

2019

 

Commercial paper outstanding, net of discounts

$

$

252,323

Weighted average interest rate

 

%

 

1.88

%

At September 30, 2020, $500.0 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 8 – Long-Term Debt.

NOTE 10 – ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS

We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation 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 in a manner consistent with the depreciation of the underlying physical 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.

Environmental reclamation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred. Such cost estimates may include ongoing care, maintenance and monitoring costs. Changes in reclamation estimates are reflected in earnings in the period an estimate is revised. Estimates of future expenditures for environmental reclamation obligations are not discounted.

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

12


Mine is currently in post-reclamation monitoring. One pit at the Colowyo Mine began final reclamation in 2018 with the other remaining pits still being actively mined.

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 and environmental reclamation obligations are as follows (dollars in thousands):

Nine Months Ended

September 30, 

    

2020

    

Obligations at beginning of period

$

78,914

Liabilities incurred

 

Liabilities settled

 

(824)

Accretion expense

 

1,895

Change in cash flow estimate

 

3,158

Total obligations at end of period

$

83,143

Less current obligations at end of period

(2,840)

Long-term obligations at end of period

$

80,303

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

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, 

 

    

2020

    

2019

 

Transmission easements

$

20,148

$

20,549

Operating lease liabilities - noncurrent

1,705

1,846

Contract liabilities (unearned revenue) - noncurrent

 

3,781

 

4,217

Customer deposits

 

7,404

 

3,015

Financial liabilities - reclamation

 

10,217

 

12,091

Other

13,222

14,681

Total other deferred credits and other liabilities

$

56,477

$

56,399

In 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $31.2 million will be paid by us for these easements from 2020 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $20.1 and $20.5 million as of September 30, 2020 and December 31, 2019, 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.

13


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, 2020, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles.

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):

Nine Months Ended

September 30, 

    

2020

Postretirement medical benefit obligation at beginning of period

$

10,195

Service cost

 

422

Interest cost

 

264

Benefit payments (net of contributions by participants)

 

(465)

Postretirement medical benefit obligation at end of period

$

10,416

Postemployment medical benefit obligation at end of period

 

375

Total postretirement and postemployment medical obligations at end of period

$

10,791

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.

14


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):

Nine Months Ended

September 30, 

    

2020

Accumulated other comprehensive loss at beginning of period

$

(1,387)

Amortization of actuarial (gain) loss into income

 

11

Amortization of prior service credit into other income

(59)

Accumulated other comprehensive loss at end of period

$

(1,435)

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.

The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

Nine Months Ended

September 30, 

    

2020

Executive benefit restoration obligation at beginning of period

$

674

Service cost

 

312

Interest cost

 

417

Plan amendments - prior service cost

5,218

Benefit payments

 

(715)

Actuarial loss

 

2,155

Executive benefit restoration at end of period

$

8,061

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 defined benefit pension plans, 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 executive benefit restoration obligation.

15


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

Nine Months Ended

September 30, 

    

2020

Accumulated other comprehensive loss at beginning of period

$

(130)

Plan amendments - prior service cost

 

(5,218)

Amortization of prior service cost into other income

1,336

Unrecognized actuarial loss

(2,155)

Accumulated other comprehensive loss at end of period

$

(6,167)

NOTE 13 – REVENUE

Revenue from Contracts with Customers

Our revenues are derived primarily from the sale of electric power to our Utility Members pursuant to long-term wholesale electric service contracts. Our contracts with our 42 Utility Members extend through 2050. We had a contract with DMEA that extended through 2040. DMEA withdrew from membership in us on June 30, 2020 and DMEA’s contract was assigned by us to DMEA’s new third-party power supplier.

Member electric sales

Revenues from electric power sales to our Utility Members are primarily from our Class A rate schedule filed with FERC. Our Class A rate schedule for electric power sales to our Utility 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 and FERC. Energy and demand have the same pattern of transfer to our Utility Members and are both measurements of the electric power provided to our Utility Members. Therefore, the provision of electric power to our Utility Members is one performance obligation. Prior to our Utility 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 Utility Member requires each incremental unit of electric power. We transfer control of the electric power to our Utility Members over time and our Utility 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 Utility Members are invoiced based on the meter reading. Payments from our Utility Members are received in accordance with the wholesale electric service contracts’ terms, which is less than 30 days from the invoice date. Utility Member electric sales revenue is recorded as Utility Member electric sales on our consolidated statements of operations and Accounts receivable – Utility Members on our consolidated statements of financial position.

16


In addition to our Utility 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, 

2020

    

2019

2020

2019

Non-member electric sales:

    

Long-term contracts

$

9,423

$

12,647

$

32,817

$

35,241

Short-term contracts

29,183

15,692

38,227

36,602

Other

16,226

12,128

37,150

39,540

Total non-member electric sales and other operating revenue

$

54,832

$

40,467

$

108,194

$

111,383

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 wheeling, transmission and lease revenues, coal sales and revenue from supplying steam and water. Other operating revenue also includes revenue we receive from two of our Non-Utility Members. 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 is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection 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 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, which expired on June 30, 2019, that was required to be accounted for as an operating lease since the arrangement conveyed 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

17


statements of operations includes only the current provision. This liability method is included in our rate filing accepted by FERC on March 20, 2020; however, FERC may require a different method for the recovery of income taxes. Our consolidated statements of operations included an income tax benefit of $0.5 million for the nine months ended September 30, 2020 and $0.2 million for the comparable period in 2019. These income tax benefits are due to an alternative minimum tax credit refund.

During the first quarter of 2020, we recorded a $19 million decrease in our deferred tax asset valuation allowance due to the deferred tax treatment of an abandonment loss. No further changes to the valuation allowance were needed for the nine-month period ended September 30, 2020.

The Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) was signed into law on March 27, 2020. The CARES Act includes certain corporate income tax provisions which have been evaluated by us. The CARES Act did not have a material impact on our consolidated financial statements.

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 various facilities and operational assets and had a lease agreement for the right to use power generating equipment at Brush Generating Station. Under the power purchase arrangement at the Brush Generating Station that expired on December 31, 2019, we were 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 whereby we provide our own natural gas for generation of electricity. We did not renew this power purchase arrangement.

Rent expense for all short-term and long-term operating leases was $1.2 million for the three months ended September 30, 2020 and $1.8 million for the comparable period in 2019. Rent expense for all short-term and long-term operating leases was $2.8 million for the nine months ended September 30, 2020 and $5.4 million for the comparable period in 2019. Rent expense is included in operating expenses on our consolidated statements of operations. As of September 30, 2020, there were no arrangements accounted for as finance leases.

18


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

September 30, 

December 31, 

2020

2019

Operating leases

Operating lease right-of-use assets

$

11,464

$

8,376

Less: Accumulated amortization

(1,378)

(754)

Net operating lease right-of-use assets

$

10,086

$

7,622

Operating lease liabilities - current

$

(556)

$

(5,533)

Operating lease liabilities - noncurrent

(1,705)

(1,846)

Total operating lease liabilities

$

(2,261)

$

(7,379)

Operating leases

Weighted average remaining lease term (years)

7.46

9.5

Weighted average discount rate

3.83%

3.80%

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

Year 1

    

$

609

Year 2

 

444

Year 3

 

341

Year 4

 

315

Year 5

196

Thereafter

 

737

Total lease payments

$

2,642

Less imputed interest

(381)

Total

$

2,261

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 $1.8 million and $1.6 million for the three months ended September 30, 2020 and 2019, respectively, and $5.0 million and $10.5 million for the nine months ended September 30, 2020 and 2019, respectively, are included in other operating revenue on our consolidated statements of operations.

The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 17- Variable Interest Entities. However, as the noncontrolling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded. See Note 14 – Income Taxes.

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

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participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows:

Level 1 inputs 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):