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 March 31, 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 MARCH 31, 2020

		Page Number
PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Financial Position as of March 31, 2020 (unaudited) and December 31, 2019	1
	Consolidated Statements of Operations — Three Months Ended March 30, 2020 and 2019 (unaudited)	2
	Consolidated Statements of Comprehensive Income — Three Months Ended March  31, 2020 and 2019 (unaudited)	3
	Consolidated Statements of Equity — Three Months Ended March  31, 2020 and 2019 (unaudited)	4
	Consolidated Statements of Cash Flows — Three Months Ended March  31, 2020 and 2019 (unaudited)	5
	Notes to Unaudited Consolidated Financial Statements For the Three Months Ended March  31, 2020 and 2019	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34
PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A	Risk Factors	36
Item 4.	Mine Safety Disclosures	36
Item 6.	Exhibits	36
SIGNATURES

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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.

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PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Financial Position

(dollars in thousands)

	March 31, 2020		December 31, 2019
ASSETS		(unaudited)
Property, plant and equipment
Electric plant
In service	$	6,126,271	$	6,090,392
Construction work in progress		156,996		164,924
Total electric plant		6,283,267		6,255,316
Less allowances for depreciation and amortization		(2,928,176)		(2,641,470)
Net electric plant		3,355,091		3,613,846
Other plant		412,291		409,051
Less allowances for depreciation, amortization and depletion		(122,495)		(113,607)
Net other plant		289,796		295,444
Total property, plant and equipment		3,644,887		3,909,290
Other assets and investments
Investments in other associations		162,562		161,945
Investments in and advances to coal mines		19,689		19,681
Restricted cash and investments		4,967		30,516
Other noncurrent assets		8,512		8,654
Total other assets and investments		195,730		220,796
Current assets
Cash and cash equivalents		180,682		83,070
Restricted cash and investments		188		182
Deposits and advances		35,856		28,434
Accounts receivable—Utility Members		97,901		105,371
Other accounts receivable		21,212		28,039
Coal inventory		48,348		50,191
Materials and supplies		92,677		93,632
Total current assets		476,864		388,919
Deferred charges
Regulatory assets		732,784		497,279
Prepayment—NRECA Retirement Security Plan		25,519		26,862
Other		56,122		42,672
Total deferred charges		814,425		566,813
Total assets	$	5,131,906	$	5,085,818
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity	$	1,026,453	$	1,031,063
Accumulated other comprehensive income (loss)		(7,958)		(1,518)
Noncontrolling interest		111,768		111,717
Total equity		1,130,263		1,141,262
Long-term debt		3,217,571		3,063,351
Total capitalization		4,347,834		4,204,613
Current liabilities
Utility Member advances		11,120		18,025
Accounts payable		100,153		99,033
Short-term borrowings		164,723		252,323
Accrued expenses		35,855		43,761
Current asset retirement obligations		1,802		2,460
Accrued interest		47,037		29,716
Accrued property taxes		27,066		29,129
Current maturities of long-term debt		85,636		81,555
Total current liabilities		473,392		556,002
Deferred credits and other liabilities
Regulatory liabilities		122,051		122,169
Deferred income tax liability		33,969		58,937
Asset retirement and environmental reclamation obligations		81,078		76,454
Other		54,395		56,399
Total deferred credits and other liabilities		291,493		313,959
Accumulated postretirement benefit and postemployment obligations		19,187		11,244
Total equity and liabilities	$	5,131,906	$	5,085,818

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Operations (unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2020		2019
Operating revenues
Utility Member electric sales	$	292,763		298,931
Non-member electric sales		15,813		26,730
Other		10,890		14,256
		319,466		339,917
Operating expenses
Purchased power		71,015		70,956
Fuel		61,069		85,149
Production		43,188		47,761
Transmission		41,540		39,142
General and administrative		16,215		10,813
Depreciation, amortization and depletion		47,024		38,145
Coal mining		2,734		3,596
Other		7,683		3,838
		290,468		299,400
Operating margins		28,998		40,517
Other income
Interest		1,305		1,415
Capital credits from cooperatives		3,353		2,997
Other income (expense)		(250)		1,281
		4,408		5,693
Interest expense
Interest		38,867		40,652
Interest charged during construction		(1,961)		(2,371)
		36,906		38,281
Income tax benefit		(209)		(77)
Net margins including noncontrolling interest		(3,291)		8,006
Net margin attributable to noncontrolling interest		(1,319)		(1,017)
Net margins attributable to the Association	$	(4,610)	$	6,989

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Comprehensive Income (unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2020		2019
Net margins including noncontrolling interest	$	(3,291)	$	8,006
Other comprehensive loss:
Amortization of actuarial loss on postretirement benefit obligation included in net margin		933		33
Unrecognized prior service cost		(7,373)		(214)
Other comprehensive loss		(6,440)		(181)
Comprehensive income (loss) including noncontrolling interest		(9,731)		7,825
Net comprehensive income attributable to noncontrolling interest		(1,319)		(1,017)
Comprehensive income (loss) attributable to the Association	$	(11,050)	$	6,808

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Equity (unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2020		2019
Patronage capital equity at beginning of period	$	1,031,063	$	1,015,754
Net margins attributable to the Association		(4,610)		6,989
Patronage capital equity at end of period		1,026,453		1,022,743
Accumulated other comprehensive income (loss) at beginning of period		(1,518)		375
Amortization of prior service cost		933		33
Unrecognized prior service cost		(7,373)		(214)
Accumulated other comprehensive income (loss) at end of period		(7,958)		194
Noncontrolling interest at beginning of period		111,717		110,169
Net comprehensive income attributable to noncontrolling interest		1,319		1,017
Equity distribution to noncontrolling interest		(1,268)		(1,454)
Noncontrolling interest at end of period		111,768		109,732
Total equity at end of period	$	1,130,263	$	1,132,669

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Cash Flows (unaudited)

(dollars in thousands)

	Three Months Ended March 31,
	2020		2019
Operating activities
Net margins including noncontrolling interest	$	(3,291)	$	8,006
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion		47,024		38,145
Amortization of intangible asset		—		1,831
Amortization of NRECA Retirement Security Plan prepayment		1,343		1,343
Amortization of debt issuance costs		602		577
Impairment loss		259,761		—
Deferred impairment loss		(268,163)		—
Capital credit allocations from cooperatives and income from coal mines over refund distributions		(693)		(265)
Changes in operating assets and liabilities:
Accounts receivable		14,230		3,510
Coal inventory		1,843		13,442
Materials and supplies		954		(3,360)
Accounts payable and accrued expenses		8,039		1,876
Accrued interest		17,321		16,787
Accrued property taxes		(2,063)		(1,692)
Other		(11,353)		(26)
Net cash provided by operating activities		65,554		80,174
Investing activities
Purchases of plant		(36,171)		(45,128)
Changes in deferred charges		(6,094)		(4,220)
Proceeds from other investments		68		65
Net cash used in investing activities		(42,197)		(49,283)
Financing activities
Changes in Utility Member advances		(6,905)		(4,407)
Payments of long-term debt		(41,994)		(36,264)
Proceeds from issuance of long-term debt		200,000		—
Debt issuance costs		—		(13)
Increase (decrease) in short-term borrowings, net		(87,600)		20,063
Retirement of patronage capital		(13,326)		(11,101)
Equity distribution to noncontrolling interest		(1,268)		(1,454)
Other		(195)		(176)
Net cash provided by (used in) financing activities		48,712		(33,352)
Net increase (decrease) in cash, cash equivalents and restricted cash and investments		72,069		(2,461)
Cash, cash equivalents and restricted cash and investments – beginning		113,768		127,590
Cash, cash equivalents and restricted cash and investments – ending	$	185,837	$	125,129
Supplemental cash flow information:
Cash paid for interest	$	21,222	$	23,604
Cash paid for income taxes	$	—	$	—
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$	1,044	$	(629)

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

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Tri-State Generation and Transmission Association, Inc.

Notes to Unaudited Consolidated Financial Statements

For the Three Months Ended March 31, 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 March 31, 2020, results of operations for the three months ended March 31, 2020 and 2019, and cash flows for the three months ended March 31, 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 Class C - non-utility members. For our Class A members, we provide electric power to our forty-three electric distribution member systems (“Class A Member(s)”) 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.

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Our share in each jointly owned facility is as follows as of March 31, 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	%	$	396,334	$	249,757	$	201
MBPP - Laramie River Station	27.13	%		488,879		299,348		3,868
Total			$	885,213	$	549,105	$	4,069

Recently Adopted Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses in Financial Instruments. FASB issued subsequent amendments to the initial guidance in November 2018 with ASU 2018-19, in April 2019 with ASU 2019-04, and in May 2019 with ASU 2019-05. The ASU amends the guidance on the impairment of financial instruments and adds an impairment model, known as the current expected credit loss (“CECL”) model. The CECL model requires an entity to recognize its current estimate of all expected credit losses, rather than incurred losses, and applies to trade receivables and other receivables. The CECL model is designed to capture expected credit losses through the establishment of an allowance account, which will be presented as an offset to the amortized cost basis of the related financial asset. The new guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and is applied using the modified-retrospective approach. We have evaluated the impact of this ASU and have adopted this standard for the fiscal year beginning January 1, 2020. The adoption of this standard did not have an impact on our consolidated statements of financial position or consolidated statements of operations.

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.

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

	March 31,		December 31,
	2020		2019
Regulatory assets
Deferred income tax expense (1)	$	33,970	$	58,937
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)		83,142		83,714
Goodwill – J.M. Shafer (3)		48,433		49,145
Goodwill – Colowyo Coal (4)		36,936		37,194
Deferred debt prepayment transaction costs (5)		138,774		140,931
Deferred Holcomb expansion impairment loss (6)		92,325		93,494
Unrecovered plant (7)		299,204		33,864
Total regulatory assets		732,784		497,279
Regulatory liabilities
Interest rate swap - realized gain (8)		3,626		3,744
Deferred revenues (9)		75,853		75,853
Membership withdrawal (10)		42,572		42,572
Total regulatory liabilities		122,051		122,169
Net regulatory asset	$	610,733	$	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.

(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 other operating expenses 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. In May 2020, we filed an accounting filing

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with FERC to request regulatory treatment for the Escalante Generating Station impaired loss and believe it is probable that FERC will allow us to recover the costs in our rates. If required, we will make a Section 205 filing under the Federal Power Act in connection with any future rate change resulting from the decommission of the Escalante Generating Station. 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 recorded in connection with the withdrawal of a former Utility Member from membership in us. This deferred membership withdrawal income will be refunded to Utility 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):

	March 31,		December 31,
	2020		2019
Basin Electric Power Cooperative	$	117,368	$	117,368
National Rural Utilities Cooperative Finance Corporation - patronage capital		11,761		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.		2,193		2,409
Other		4,214		4,253
Investments in other associations	$	162,562	$	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 three months ended March 31, 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.

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

	March 31,		December 31,
	2020		2019
Investment in Trapper Mine	$	16,014	$	15,881
Advances to Dry Fork Mine		3,675		3,800
Investments in and advances to coal mines	$	19,689	$	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.

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):

	March 31,		December 31,
	2020		2019
Cash and cash equivalents	$	180,682	$	83,070
Restricted cash and investments - current		188		182
Restricted cash and investments - noncurrent		4,967		30,516
Cash, cash equivalents and restricted cash and investments	$	185,837	$	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 has internally restricted cash in the amount of $0.1 million and $25.5 million as of March 31, 2020 and December 31, 2019, respectively, which is 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 as of December 31, 2019 related to deferred revenue 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 three months ended March 31, 2020,

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we recognized $0.3 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):

	March 31,		December 31,
	2020		2019
Accounts receivable - Utility Members	$	97,901	$	105,371
Other accounts receivable - trade:
Non-member electric sales		3,918		4,727
Other		16,601		20,628
Total other accounts receivable - trade		20,519		25,355
Other accounts receivable - nontrade		693		2,684
Total other accounts receivable	$	21,212	$	28,039
Contract liabilities (unearned revenue)	$	6,825	$	7,041

NOTE 7 – OTHER DEFERRED CHARGES

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

	March 31,		December 31,
	2020		2019
Preliminary surveys and investigations	$	22,167	$	21,261
Advances to operating agents of jointly owned facilities		10,197		3,917
Operating lease right-of-use assets		8,327		7,622
Other		15,431		9,872
Total other deferred charges	$	56,122	$	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 $3.3 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 $25.3 million as of March 31, 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

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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 long-term debt 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, 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 March 31, 2020, we have borrowed $200 million in LIBOR rate loans which are secured under the Revolving Credit Agreement, and issued $165 million in commercial paper against the commercial paper back-up sublimit. As of March 31, 2020, we had $285.0 million in availability under the Revolving Credit Agreement.

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

	March 31,		December 31,
	2020		2019
Total debt	$	3,324,478		3,166,472
Less debt issuance costs		(26,810)		(27,412)
Less debt discounts		(9,846)		(9,906)
Plus debt premiums		15,385		15,752
Total debt adjusted for debt issuance costs, discounts and premiums		3,303,207		3,144,906
Less current maturities		(85,636)		(81,555)
Long-term debt	$	3,217,571	$	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):

	March 31,			December 31,
	2020			2019
Commercial paper outstanding, net of discounts	$	164,723		$	252,323
Weighted average interest rate		1.83	%		1.88	%

At March 31, 2020, $285.0 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

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

	Three Months Ended
		March 31,
		2020
Obligations at beginning of period		$	78,914
Liabilities incurred			—
Liabilities settled			—
Accretion expense			629
Change in cash flow estimate			3,337
Total obligations at end of period		$	82,880
Less current obligations at end of period			(1,802)
Long-term obligations at end of period		$	81,078

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):

	March 31,		December 31,
	2020		2019
Transmission easements	$	20,235	$	20,549
Operating lease liabilities - noncurrent		1,921		1,846
Contract liabilities (unearned revenue) - noncurrent		4,123		4,217
Customer deposits		2,251		3,015
Financial liabilities - reclamation		12,070		12,091
Other		13,795		14,681
Total other deferred credits and other liabilities	$	54,395	$	56,399

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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 $20.2 and $20.5 million as of March 31, 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.

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 March 31, 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):

	March 31,
	2020
Postretirement medical benefit obligation at beginning of period	$	10,195
Service cost		141
Interest cost		88
Benefit payments (net of contributions by participants)		(155)
Postretirement medical benefit obligation at end of period	$	10,269
Postemployment medical benefit obligation at end of period		375
Total postretirement and postemployment medical obligations at end of period	$	10,644

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.

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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):

	2020
Amounts included in accumulated other comprehensive income at beginning of period	$	(1,387)
Amortization of actuarial (gain) loss into income		11
Amortization of prior service credit into other income		(20)
Amounts included in accumulated other comprehensive income at end of period	$	(1,396)

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):

	March 31,
	2020
Executive benefit restoration obligation at beginning of period	$	674
Service cost		206
Interest cost		291
Plan amendments - prior service cost		5,218
Actuarial loss		2,155
Executive benefit restoration at end of period	$	8,544

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.

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):

	March 31,
	2020
Amounts included in accumulated other comprehensive income at beginning of period	$	(130)
Plan amendments - prior service cost		(5,218)
Amortization of prior service cost into other income		942
Unrecognized actuarial loss		(2,155)
Amounts included in accumulated other comprehensive income at end of period	$	(6,561)

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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 Utility Members extend through 2050 for 42 Utility Members and 2040 for the remaining Utility Member.

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.

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 March 31,
	2020		2019
Non-member electric sales:
Long-term contracts	$	12,144	$	11,682
Short-term contracts		3,669		15,048
Other		10,890		14,256
Total non-member electric sales and other operating revenue	$	26,703	$	40,986

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

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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 was issued). 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 statements of operations includes only the current provision. This liability method is included in our rate filling 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 $0.2 million for the three months ended March 31, 2020 and $0.1 million for the comparable period in 2019. These income tax benefits are due to an alternative minimum tax credit refund.

During the three months ended March 31, 2020, we recorded a decrease in our deferred tax asset valuation allowance due to the deferred tax treatment of an abandonment loss. We concluded that a valuation allowance of $19.0 million was more likely than not needed based on the expected realization of deferred tax assets for the period ended March 31, 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

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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 $0.9 million for the three months ended March 31, 2020 and $1.8 million for the comparable period in 2019. Rent expense is included in operating expenses on our consolidated statements of operations. As of March 31, 2020, there were no arrangements accounted for as finance leases.

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

	March 31,
	2020
Operating leases
Operating lease right-of-use assets	$	9,312
Less: Accumulated amortization		(985)
Net operating lease right-of-use assets	$	8,327
Operating lease liabilities - current	$	(6,355)
Operating lease liabilities - noncurrent		(1,921)
Total operating lease liabilities	$	(8,276)
Operating leases
Weighted average remaining lease term (years)		9.3
Weighted average discount rate		3.75%

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

Year 1	$	6,430
Year 2		526
Year 3		364
Year 4		334
Year 5		284
Thereafter		779
Total lease payments	$	8,717
Less imputed interest		(441)
Total	$	8,276

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 $4.3 million for the three months ended March 31, 2020 and 2019, respectively, respectively, are included in other operating revenue on our consolidated statements of operations.

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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 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):

	March 31, 2020				December 31, 2019
			Estimated				Estimated
	Cost		Fair Value		Cost		Fair Value
Marketable securities	$	528	$	400	$	715	$	654

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 $114.8 million as of March 31, 2020 and $79.0 million as of December 31, 2019.

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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):

	March 31, 2020				December 31, 2019
	Principal		Estimated		Principal		Estimated
	Amount		Fair Value		Amount		Fair Value
Total debt	$	3,324,478	$	4,140,708	$	3,166,472	$	3,608,341

NOTE 17 – VARIABLE INTEREST ENTITIES

The following is a description of our financial interests in variable interest entities that weconsider 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):

	March 31,		December 31,
	2020		2019
Net electric plant	$	771,876	$	776,411
Noncontrolling interest		111,768		111,717
Long-term debt		343,313		380,867
Accrued interest		3,977		11,050

Our consolidated statements of operations include the following Springerville Partnership expenses for the three months ended March 31, 2020 and 2019 (dollars in thousands):

		March 31,		March 31,
	2020		2019
Depreciation, amortization and depletion	$	4,534	$	4,534
Interest		5,861		6,831

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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 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 $2.2 million at March 31, 2020 and $2.4 million at December 31, 2019 and is included in investments in other associations.

Western Fuels – Wyoming (“WFW”):  WFW, the owner and operator of the Dry Fork Mine in Gillette, Wyoming, 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 March 31, 2020 and December 31, 2019 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 $16.0 million at March 31, 2020 and $15.9 million at December 31, 2019.

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.

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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 notified us and the other entity of its intent to arbitrate in accordance with the agreement and claimed damages caused by the alleged breach of approximately $6.9 million, plus interest, attorney fees, and any future damages. The other entity filed a cross-claim against us claiming we are responsible for such entity’s share of any damages. The matter was scheduled for arbitration to commence in January 2020. The arbitration was cancelled and the parties continue to discuss a resolution of this matter. It is not possible to predict whether this matter will be resolved without arbitration or whether we will incur any liability in connection with this matter.

At our July 2019 Board meeting, our Board authorized us to take action to place us under wholesale rate regulation by FERC. On September 3, 2019, a membership agreement with a Non-Utility Member, MIECO, Inc., became effective. The admission of the new Non-Utility 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 (“FPA”). During the week of December 23, 2019, we filed our tariff filings, including our stated rate cost of service filing, market based rate authorization, and transmission Open Access Transmission Tariff. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order (“PDO”) with FERC asking FERC to confirm our jurisdiction under the FPA and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission (“COPUC”) to address any rate related issues. Numerous parties filed interventions or protests with FERC. Some of the interveners and protestors, including some of our Utility Members and the COPUC alleged that we are not FERC jurisdictional and are still exempt from FERC wholesale rate regulation pursuant to the FPA. On March 20, 2020, FERC issued orders regarding our PDO and our tariff filings. FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC did provide that FERC will not require refunds for our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC did not impose any civil penalties on us. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered a 206 proceeding to determine the justness and reasonableness of our rates and wholesale electric service contracts. The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. The settlement proceedings are continuing. Any refunds to the applicable tariff rates would only apply to after the above referenced dates. On April 13, 2020, we filed a request for rehearing limited to the issue of preemption of the COPUC related to the contract termination payment number as described in our PDO. Requests for rehearing related to both the PDO and tariff filings have been filed with FERC by other parties. It is not possible to predict if FERC will require us to refund amounts to our customers for sales after the above referenced date, if FERC will approve our current practices regarding use of regulatory assets are just and reasonable, or to estimate any liability associated with this matter. In addition, we cannot predict the outcome of the 206 proceedings, our April 13 request for rehearing or any other request for rehearing filed with FERC.

On May 4, 2020, United Power, Inc. (“United”) filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court alleging, among other things, that the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, and that we have breached the wholesale electric service contract with United. We are evaluating the complaint filed by United.

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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 were formed by our utility member systems, or Utility Members, for the purpose of providing wholesale power and transmission services to our Utility Members (which are distribution electric cooperatives and public power districts) for their resale of the power to their retail consumers. Our Utility Members 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 Utility 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 are owned entirely by our forty-six members.We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and Class C - non-utility members. For our forty‑three Class A members, or Class A Members, we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members, and therefore all our Utility Members are currently Class A Members. We have three non-utility members, or Non-Utility Members. Our Utility Members and Non-Utility Members are collectively referred to as our “Members.”  Thirty-nine of our Utility Members are not-for-profit, electric distribution cooperative associations. Four Utility Members are public power districts, which are political subdivisions of the State of Nebraska. We became regulated as a public utility under Part II of the Federal Power Act, or FPA, on September 3, 2019 when we admitted a Non-Utility Member, MIECO, Inc. (a non-governmental/non-electric cooperative entity), as a new Member/owner.

We supply and transmit our Utility 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 4,317 megawatts, or MWs, of which approximately 1,059 MWs comes from renewables. In 2019, we estimate that nearly a third of the energy delivered by us and our Utility Members to our Utility Members’ customers came from non-carbon emitting resources.

We sold 4.3 million megawatt hours, or MWhs, for the three months ended March 31, 2020, of which 92.9 percent was to Utility Members. Total revenue from electric sales was $308.6 million for the three months ended March 31, 2020, of which 94.9 percent was from Utility Member sales. Our results for the three months ended March 31, 2020 were primarily impacted by seasonal weather changes.

· Non-member electric sales decreased by $10.9 million, or 40.8 percent, primarily due to decreased short-term market sales and overall decreased generation from our generating stations.

· Fuel expense decreased $24.0 million, or 28.2 percent, primarily due to lower generation from our generating facilities during the period as well as an environmental reclamation obligation at New Horizon Mine recognized during the three months ended March 31, 2019.

Our Bylaws and Wholesale Electric Service Contracts

Pursuant to our Bylaws, each Utility Member is required to purchase from us the electric power and energy provided in the wholesale electric service contract with such Utility Member. Our wholesale electric service contracts with our Utility Members extending through 2050 for 42 Utility Members (which constitute approximately 96.2 percent of our revenue from Utility Member sales for the three months ended March 31, 2020) and extending through 2040 for the remaining Utility 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 Utility Member and obligates the Utility Member to purchase and receive, at least 95 percent of its electric power requirements from us. Each Utility Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled

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by the Utility Member. As of March 31, 2020,  21 Utility Members have enrolled in this program with capacity totaling approximately 136 MWs of which 128 MWs are in operation.

Pursuant to our wholesale electric service contracts with our Utility Members, we convened a contract committee in 2019 and 2020, consisting of a representative from each Utility Member, to review the wholesale electric service contracts and to discuss alternative contracts for our Utility Members, including partial requirements contracts.  Upon recommendations from the contract committee, in March 2020, our Board of Directors, or Board, established two classes of Utility Members:  Class A - Utility Full Requirements and Class B – Utility Partial Requirements.  Both classes of membership will be full-requirements transmission Utility Members with the term of all contracts remaining unchanged and continuing to extend through 2050. An open season for Class A  Members and Class B  members will be declared with at least three months of notice with a 300 MW system limit.  Class A Members that elect to become Class B members shall be subject to a buy-down payment.  In April 2020, the Board approved the terms and conditions for a buy-down payment formula for a Class A Member to become a Class B member that will make other Utility Members financially whole.

Pursuant to our Bylaws, a Utility 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 Utility 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. In April 2020, the Board approved a “Make-Whole” methodology for a contract termination payment designed to leave remaining Utility Members in the same economic position after a Utility Member terminates its wholesale electric service contract as the remaining Utility Members would have been had the Utility Member not terminated.  Any termination of a Utility Member wholesale electric service contract shall continue to require Board approval.  In April 2010, we filed with the Federal Energy Regulatory Commission, or FERC. the Board approved contract termination payment methodology.

In July 2019, we reached a settlement with DMEA that provides for their withdrawal from membership in us as permitted by our Bylaws, the resolution of all litigation with DMEA regarding various matters, the transfer of certain transmission assets to DMEA, the forfeiture by DMEA of the current balance of DMEA’s patronage capital allocation, 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 are set forth in a withdrawal agreement. In April 2020, we entered into the membership withdrawal agreement and an associated purchase and sales agreement with DMEA for the sale of certain assets and facilities to DMEA. The withdrawal agreement, which is subject to receipt of certain approvals, including by FERC, and other conditions, provides for the withdrawal of DMEA from membership in us, the assignment by us of DMEA’s wholesale electric service contract to DMEA’s new third-party power supplier, and the conveyance of certain assets and facilities by us to DMEA pursuant to the purchase and sales agreement.  Under the withdrawal agreement, DMEA agreed to make a cash payment of $88.5 million to us at the withdrawal date, which includes $26 million for the assets, and the retirement by us and forfeiture by DMEA of the current balance of DMEA’s patronage capital allocation, which is approximately $48 million. The withdrawal agreement provides for and we anticipate, subject to receipt of certain approvals, for the withdrawal date to occur at the end of day on June 30, 2020. If a Colorado Public Utilities Commission, or COPUC, approval related to the conveyance of certain assets and facilities to DMEA is delayed, we and DMEA may agree to proceed with all of the other items referenced above to occur on the withdrawal date other than conveyance of such assets and facilities, which conveyance and payment for the assets and facilities will then occur in accordance with the purchase and sales agreement promptly after receipt of such approval.

In November 2019, La Plata Electric Association, Inc., or 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 Utility Members with contract termination payment numbers is unlawful. LPEA seeks for the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the contract termination payment number. 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 Utility Member under a partial requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory contract termination payment number. United seeks for

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the COPUC to issue an order establishing a contract termination payment number. The COPUC has consolidated the proceeding. The matter has been set for hearing the week of May 18, 2020. See “LEGAL PROCEEDINGS.”

In May 2020, United filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court alleging, among other things, that the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, and that we have breached the wholesale electric service contract with United. We are evaluating the complaint filed by United. See “LEGAL PROCEEDINGS.”

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 Utility Member flexibility,  all with a goal to lower wholesale rates to our Utility Members. In January 2020, we announced the actions of our Responsible Energy Plan, which advance our cleaner generation portfolio and programs to serve our Utility Members. Some of the actions of the Responsible Energy Plan include:

· Reducing emissions by eliminating 100 percent of emissions from our New Mexico coal-fired generating facilities by the end of 2020 and from our Colorado coal-fired generating facilities by 2030.

· Increasing clean energy by bringing over 1 gigawatt of wind and solar resources online by 2024, meaning 50 percent of the energy consumed by our Utility Members customers is expected to come from renewables by 2024.

· Increasing Utility Member flexibility to develop more local, self-supplied renewable energy.

· Extending benefits of a clean grid across the economy through expanded electric vehicle infrastructure and beneficial electrification.

For further information regarding our Responsible Energy Plan, see “Item 1 – BUSINESS — MEMBERS” in our annual report on Form 10-K for the year ended December 31, 2019.

Early Retirements of Generating Facilities

As part of our Responsible Energy Plan, in January 2020, our Board approved the early retirement of Escalante Generating Station by the end of 2020 and Craig Generating Station Units 2 and 3 and the Colowyo Mine by 2030. The early retirement of Craig Generating Station Unit 1 by December 31, 2025 remains unchanged.

In the first quarter of 2020, in accordance with accounting requirements, we recognized an impairment loss of $268.2 million associated with the early retirement of Escalante Generating Station. Our Board approved the deferral of such impairment loss as a regulatory asset. This loss 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. Such deferral and recovery is subject to approval by FERC. Craig Generating Station Units 2 and 3 continue to be depreciated over the last rate study end lives of 2039 and 2044. Once it becomes probable that FERC will approve the impairment and recovery of unrecovered depreciation associated with the closure of Craig Generating Station Units 2 and 3, then the expected unrecovered depreciation at the time of the closure will be impaired and recovered from our Utility Members through rates. The net book value of Craig Generating Station Units 2 and 3 was $430.1 million as of March 31, 2020. The shortened life of Colowyo Mine increases annual depreciation, amortization and depletion expense in the amount of approximately $12.7 million.

In connection with such early retirements, our Board continues to evaluate the creation of regulatory assets and use of regulatory liabilities to ensure our Utility Member rates remain stable, if not lower, during this transition. A creation of regulatory assets to defer expenses associated with these early retirements or the utilization of regulatory liabilities would require FERC approval.

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COVID‑19 Impacts

The global coronavirus (COVID‑19) pandemic has adversely impacted economic activity and conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions.

We are intensely focused on safely delivering power to our Utility Members and ensuring the reliability of the regional power grid, protecting our employees’ health, and supporting state and national directives to stem the spread of COVID‑19 in our communities. We have activated established programs and procedures to mitigate the impacts of pandemics and protect our employees from communicable diseases. Our Crisis Management Team, representing all functions of our operations, is actively assessing potential impacts to our operations and taking actions that mitigate those impacts. These actions include: ensuring our critical generation, transmission and operations teams are staffed and have the resources needed to safely operate our power system; implementing best practices to protect employees from the spread of COVID‑19, including achieving social distancing for employees through work from home programs; and postponing in-person meetings with our membership in accordance with public health directives, including postponing our annual membership meeting.  We have also supported COVID‑19 pandemic relief and recover funds in each of the four states of our Utility Members, including donations totaling $200,000.

In each of our Utility Members states, the governor of such state or officials of certain counties have implemented various and different measures related to COVID‑19, including stay-at-home orders, safer-at-home orders, and mandating the closure of certain businesses.  The various governmental measures are constantly changing and starting to allow for more businesses to re-open.

The initial economic impacts of the COVID‑19 pandemic and the various government measures related to COVID‑19 have caused a significant temporary slowdown in certain sectors of the economy, including oil and gas, and a corresponding increase in unemployment. We have experienced changes in the load patterns of our Utility Members. We continue to monitor the impacts of COVID‑19. The full extent to which the COVID‑19 pandemic may ultimately impact our results of operations depends on numerous evolving factors, which are highly uncertain and difficult to predict, including new information which may quickly emerge concerning the severity of the virus, the scope of the outbreak and the actions to contain the virus or treat its impact, and to what extent normal economic and operating conditions can resume, among others. We currently believe that we have sufficient liquidity to meet our anticipated capital and operating requirements. It is reasonably possible, however, that disruption and volatility in the global capital markets may materially increase the cost of capital. The full impact on our results of operations, financial condition, and cash flows cannot be reasonably estimated at this time.Our credit ratings are currently on negative outlook with Standard & Poor’s Global Ratings, or S&P, and Fitch Rating Inc., or Fitch.  It is possible that actual, perceived or projected negative impacts to our business or Utility Members’ businesses from the impacts of COVID-19 could be the impetus for further negative rating action.

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. As of March 31, 2020, 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, 2019.

Factors Affecting Results

Master Indenture

As of March 31, 2020, we had approximately $3.0 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

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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, or ECR, (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 Utility Members on the basis of revenue from electricity purchases from us and to our Non-Utility Members as provided in their respective membership agreement.

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 Utility 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 $415.5 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 $0.1 million as of March 31, 2020. 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 as of December 31, 2019 related to deferred revenue in response to volatile market conditions.

Rates and Regulation

At our July 2019 Board meeting, because of increased pressure by the states to regulate our rates and charges, our Board authorized us to take action to place us under wholesale rate regulation by FERC. By the addition of a non-cooperative member in 2019 and specifically by the addition of MIECO, Inc. as a Non-Utility Member on September 3, 2019, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. During the week of December 23, 2019, we filed our tariff filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. On March 20, 2020, FERC issued orders regarding our tariff filings.  FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC did provide that FERC will not require refunds for our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered a 206 proceeding to determine the justness and reasonableness of our rates, including our Class A wholesale rate schedule referenced below, and wholesale electric service contracts.  The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. Any refunds to the applicable tariff rates would only apply to after the above referenced dates. See “LEGAL PROCEEDINGS.”

Our electric sales revenues are derived from electric power sales to our Utility Members and non-member purchasers. Revenues from electric power sales to our non-member purchasers is pursuant to our market based rate authority.

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Revenues from electric power sales to our Utility Members are primarily from our Class A wholesale rate schedule filed with FERC. In 2019 and 2020, our Class A rate schedule (A-40) for electric power sales to our Utility Members consist of three billing components: an energy rate and two demand rates. Utility Member rates for energy and demand are set by our Board, consistent with the provision of reliable cost-based supply of electricity over the long term to our Utility Members. Energy is the physical electricity delivered to our Utility Members. The energy rate was billed based upon a price per kWh of physical energy delivered and the two demand rates (a generation demand and a transmission/delivery demand) were both billed based on the Utility 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.

Our Class A rate schedule (A-40) was filed at FERC as a “stated rate.” While our Board still has authority in determining our proper rates, those rates, including any change to the rate or rate structure, must be further approved by FERC subject to outside comments.

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 Utility Members and non‑member purchasers. See “– Factors Affecting Results – Rates and Regulation” for a description of our energy and demand rates to our Utility 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. 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 Utility Members’ usage of electricity include:

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

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

· the general growth in population;

· COVID-19 and governmental orders related to COVID-19, including stay-at-home orders; and

· economic conditions.

Three months ended March 31, 2020 compared to three months ended March 31, 2019

Operating Revenues

Our operating revenues are primarily derived from electric power sales to our Utility Members and non‑member purchasers. Other operating revenue consists primarily of wheeling, transmission and lease revenues, coal sales and

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revenue from supplying steam and water. Other operating revenue also includes revenue we receive from two of our Non-Utility Members. The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the three months ended March 31, 2020 and 2019 (dollars in thousands):

	Three Months Ended March 31,				Period-to-period Change
	2020		2019		Amount		Percent
Operating revenues
Utility Member electric sales	$	292,763	$	298,931	$	(6,168)		(2.1)%
Non-member electric sales		15,813		26,730		(10,917)		(40.8)%
Other		10,890		14,256		(3,366)		(23.6)%
Total operating revenues	$	319,466	$	339,917	$	(20,451)		(6.0)%
Energy sales (in MWh):
Utility Member electric sales		4,009,791		4,033,521		(23,730)		(0.6)%
Non-member electric sales		306,677		559,067		(252,390)		(45.1)%
		4,316,468		4,592,588		(276,120)		(6.0)%

· Utility Member electric sales decreased primarily due to unseasonably warmer weather during the three months ended March 31, 2020 as well as a slowdown in certain sectors of the economy during the latter half of March from the impacts of COVID-19.

· Non-member electric sales decrease primarily due to decreased short-term market sales and overall decreased generation from our generating stations. Short-term market sales decreased 258,500 MWhs, or 58.1 percent, to 186,599 MWhs for the three months ended March 31, 2020 compared to 445,099 MWhs for the same period in 2019.

Operating Expenses

Our operating expenses are primarily comprised of the costs that we incur to supply and transmit our Utility 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 March 31, 2020 and 2019 (dollars in thousands):

	Three Months Ended March 31,				Period-to-period Change
	2020		2019		Amount		Percent
Operating expenses
Purchased power	$	71,015	$	70,956	$	59		0.1%
Fuel		61,069		85,149		(24,080)		(28.3)%
Production		43,188		47,761		(4,573)		(9.6)%
Transmission		41,540		39,142		2,398		6.1%
General and administrative		16,215		10,813		5,402		50.0%
Depreciation, amortization and depletion		47,024		38,145		8,879		23.3%
Coal mining		2,734		3,596		(862)		(24.0)%
Other		7,683		3,838		3,845		100.2%
Total operating expenses	$	290,468	$	299,400	$	(8,932)		(3.0)%

· Fuel expense decreased primarily due to lower generation from our generating stations during the period and fluctuation in fuel costs. Also included in fuel expense during the first quarter of 2019 compared to the same

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period in 2020 was an additional asset retirement 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, including construction of a pond, necessary for final mine reclamation.  

· 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 administration labor and benefits.

· Depreciation, amortization and depletion expense increased primarily due to increased depreciation related to the Collom development, accelerated depletion on the coal reserves at the Colowyo Mine and a change in asset depreciable lives from 2044 to 2030 as a result of the planned early retirement of the Colowyo Mine.

· Other operating expenses increased primarily due to the write off of approximately $3.3 million of obsolete material at the Nucla Generating Station. Nucla Generating Station was officially retired on September 19, 2019.

Financial condition as of March 31, 2020 compared to December 31, 2019

The principal changes in our financial condition from December 31, 2019 to March 31, 2020 were due to increases and decreases in the following:

Assets

· Cash and cash equivalents increased $97.6 million, or 117.5 percent, to $180.7 million as of March 31, 2020 compared to $83.1 million as of December 31, 2019. The increase was primarily due to proceeds from borrowings of $200.0 million under our secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation, as lead arranger and administrative agent, or the Revolving Credit Agreement, partially offset by lower short-term borrowings and principal payments of long-term debt.

· Restricted cash and investments decreased $25.5 million, or 83.7 percent, to $5.2 million as of March 31, 2020 compared to $30.7 million as of December 31, 2019. The decrease was primarily due to the unrestricting by our Board of restricted cash related to deferred revenue in response to volatile market conditions.

· Deposits and advances increased $7.4 million, or 25.8 percent, to $35.8 million as of March 31, 2020 compared to $28.4 million as of December 31, 2019.  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 $235.5 million, or 47.4 percent, to $732.8 million as of March 31, 2020 compared to $497.3 million as of December 31, 2019. The increase was primarily due to the deferral of the $268.2 million impairment loss (including $259.8 million of impaired assets and $8.4 million of deferred severance) related to the early retirement of the Escalante Generating Station, which is expected to be retired by the end of 2020. This increase was partially offset by a decrease of $25.0 million in the deferred income tax valuation allowance related to the Holcomb abandonment tax loss and amortization of $7.7 million to depreciation, amortization and depletion expense and recovered from our Utility Members through rates.

Liabilities

· Short-term borrowings decreased $87.6 million, or 34.7 percent, to $164.7 million as of March 31, 2020 compared to $252.3 million as of December 31, 2019. Short-term borrowings consist of our commercial paper program that provides an additional financing source for our short-term liquidity needs. The decrease was due to a temporary market disruption in the commercial paper market which began around March 16, 2020 and continued through early April. During that period of time which saw elevated Tier 2 borrowing rates and shortened tenors, we borrowed under our Revolving Credit Agreement in the amount of $200 million and paid down the commercial paper by $200 million. The LIBOR draws have maturity dates of June 18, 2020 and September 20, 2020. We anticipate issuing commercial paper to pay off the LIBOR draws and for any new short-term borrowing needs assuming commercial paper market conditions remain normal. If the commercial paper market experiences disruption again then we anticipate borrowing under our Revolving Credit Agreement to roll over existing LIBOR draws and for any new short-term borrowing needs.

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· Accrued interest increased $17.3 million, or 58.3 percent, to $47.0 million as of March 31, 2020 compared to $29.7 million as of December 31, 2019. The increase was primarily due to accruals for interest payments due in future periods.

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 March 31, 2020, we had $180.7 million in cash and cash equivalents. Our committed credit arrangement as of March 31, 2020 is as follows (dollars in thousands):

				Available
	Authorized			March 31,
	Amount			2020
Revolving Credit Agreement	$	650,000	(1)	$	285,000	(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 March 31, 2020 was $365 million which was dedicated to support outstanding commercial paper of $165 million and $200 million in LIBOR rate loans under our Revolving Credit Agreement.

We have a secured Revolving Credit Agreement with aggregate commitments of $650 million. The 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 $285 million of the commercial paper back-up sublimit remained available as of March 31, 2020.  

The 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 Revolving Credit Agreement are either LIBOR rate loans or base rate loans, at our option. LIBOR rate loans bear interest at the adjusted LIBOR rate for the term of the advance plus a margin (currently 1.125 percent) based on our credit ratings. Base rate loans bear interest at the alternate base rate plus a margin (currently 0.125 percent) based on our credit ratings. The alternate base rate is the highest of (a) the federal funds rate plus ½ of 1.00 percent, (b) the prime rate, and (c) the one-month LIBOR rate plus 1.00 percent. Upon discontinuation of the LIBOR rate, the Revolving Credit Agreement provides for National Rural Utilities Cooperative Finance Corporation, or CFC, and us to endeavor to establish an alternative rate that gives due consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States. Upon discontinuation of the LIBOR rate and if no alternative rate has been established by CFC and us, all funds advances will be at base rate loans. As of March 31, 2020, we have borrowed $200 million in LIBOR rate loans under our Revolving Credit Agreement.

The 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 Revolving Credit Agreement, which was $500 million at March 31, 2020, thereby providing 100 percent dedicated support for any commercial paper outstanding. We had $165 million of commercial paper outstanding (prior to netting discounts) at March 31, 2020 and $285 million available on the commercial paper back-up sublimit at March 31, 2020.

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.

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

Cash Flow

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

Three months ended March 31, 2020 compared to three months ended March 31, 2019

Operating activities.  Net cash provided by operating activities was $65.6 million for the three months ended March 31, 2020 compared to $80.2 million for the same period in 2019, a decrease of $14.6 million. The decrease in cash provided by operating activities was primarily impacted by lower net margins including noncontrolling interest of $11.3 million, an increase in prepayments of annual insurance, memberships and licenses, a decrease in accounts receivable due to lower Utility Member electric sales, and a decrease in coal inventory. These decreases were partially offset by the timing of payment of trade payables and accrued expenses.

Investing activities.  Net cash used in investing activities was $42.2 million for the three months ended March 31, 2020 compared to $49.3 million for the same period in 2019, a decrease of $7.1 million. The decrease was primarily due to a reduction in generation and transmission improvements and system upgrades for the three months ended March 31, 2020 compared to the same period in 2019.  

Financing activities.  Net cash provided by financing activities was $48.7 million for the three months ended March 31, 2020 compared to $33.4 million for the same period in 2019, an increase in net cash provided by financing activities of $82.1 million. The increase was primarily due to $200 million of borrowings under our Revolving Credit Agreement partially offset by a decrease in short-term borrowings of $107.7 million, higher principal payments of long-term debt of $5.7 million and higher patronage capital retirements to our Members of $2.2 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 closures, facility costs, market factors and other items affecting our forecasts. After taking into account our Responsible Energy Plan, but without taking into account any changes due to COVID-19, in the years 2020 through 2024, we forecast that we may invest approximately $877 million in new facilities and upgrades to our existing facilities.

Our actual capital expenditures depend on a variety of factors, including assumptions related to our Responsible Energy Plan, Utility 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.

Contractual Commitments

Indebtedness.  As of March 31, 2020, we had $3.5 billion in outstanding obligations, including approximately $3.0 billion of debt outstanding secured on a parity basis under our Master Indenture, $165.0 million in short-term borrowings, one unsecured loan agreement totaling $25.3 million and the Springerville certificates totaling $334.0 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 CFC 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

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2016A, First Mortgage Obligations, Series 2017A, pollution control revenue bonds, and amounts outstanding, if any, under the Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Master Indenture.

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 2020 and 2041. 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. Our coal purchase obligations exclude any purchases we have with our subsidiaries.

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. For a 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, 2019.

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  our electric resource plans and directs that such plans consider the cost of carbon dioxide emissions associated with our generating facilities. On July 31, 2019, the COPUC opened a rulemaking pursuant to Senate Bill 19-236 proposing electric resource planning rules applicable to us. In April 2020, the COPUC finalized these rules which now require a process that is similar to the electric resource planning process that currently applies to Colorado’s investor owned utilities. Our first electric resource plan under the new rules is due December 1, 2020, with an initial informational filing due by June 1, 2020. The new rule that requires COPUC approval of our electric resource plans and for us to consider the cost of carbon dioxide emissions could have a material impact on our current and future generation portfolio.

Rating Triggers

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

Our 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, 2019.  

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.

As a result of COVID-19, we have activated established programs and procedures to mitigate the impacts of pandemics. While certain of our employees are telecommuting, our business continuity plans have resulted in slight changes to our processes, including how employees access our systems and approve certain work. Management believes it is taking the necessary steps to monitor and maintain appropriate internal controls over financial reporting at this time.

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, 2019.

LPEA and United COPUC Complaints.  Pursuant to our Bylaws, a Utility 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 Utility 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. 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 Utility Members with a contract termination payment number is unlawful. LPEA seeks the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the contract termination payment number. 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 Utility Member under a partial requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory contract termination payment number. United seeks for the COPUC to issue an order establishing a contract termination payment number. LPEA and United constitute approximately 6 percent and 17 percent, respectively, of our Utility Member revenue for the three months ended March 31, 2020. On November 20, 2019, the COPUC consolidated the two proceeding into one, 19F-0621E, and provided that the consolidated proceeding shall be heard before one hearing commissioner. On December 23, 2019, we filed a motion to stay the schedule in the proceeding pending the FERC’s decision on our Petition for Declaratory Order filed with FERC regarding the COPUC’s jurisdiction over us, including our Utility Members’ early termination of obligations under wholesale electric service contracts with us and withdrawal from membership in us. On February 12, 2020, by interim decision of the hearing commissioner, the hearing commissioner denied our December 23, 2019 motion to stay the proceeding and determined that the COPUC has jurisdiction over the complaints of United and LPEA and the

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complaints are ripe for review by the COPUC. A five-day evidentiary hearing was scheduled to begin on March 23, 2020, but on March 13, 2020, by interim decision of the hearing commissioner the evidentiary hearing was suspended.  On March 26, 2020, the COPUC rescinded the referral of the proceeding to a hearing commissioner and referred the matter to an administrative law judge as the hearing examiner. The hearing examiner has set the matter for hearing the week of May 18, 2020. On April 27, 2020, LPEA and United filed a motion for partial summary judgement regarding whether the COPUC has subject matter jurisdiction over the complaints filed by LPEA and United, or in the alternative, that the addition of the Non-Utility Members is invalid under Colorado law. On May 11, 2020, we filed our reply to LPEA and United’s joint motion for partial summary judgement maintaining that issues raised by LPEA and United are matters of Colorado corporate law subject to the exclusive jurisdiction of the state courts and that the admission of Non-Utility Members is not a violation of Colorado law nor of our Articles of Incorporation and Bylaws.

FERC Tariff and Declaratory Order.  Because of increased pressure by the states to regulate our rates and charges, through the addition of a non-cooperative member in 2019 and specifically by the addition of MIECO, Inc. as a Non-Utility Member on September 3, 2019, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. We filed our tariff for wholesale electric service and transmission at FERC on December 23, 2019. We filed our tariffs for wholesale electric service and transmission at FERC in stages between December 23 and 27, 2019, with supplemental filings completed by December 30, 2019. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order, or PDO, with FERC asking FERC to confirm our jurisdiction under the FPA and that FERC’s jurisdiction preempts the jurisdiction of the COPUC to address any rate related issues, including the complaints filed by United and LPEA, EL20-16-000. On March 20, 2020, FERC issued orders regarding our PDO and our tariff filings.  FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC did provide that FERC will not require refunds for our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC did not impose any civil penalties on us. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered a 206 proceeding to determine the justness and reasonableness of our rates and wholesale electric service contracts. The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. The settlement proceedings are continuing. Any refunds to the applicable tariff rates would only apply to after the above referenced dates. FERC’s March 20, 2020 order regarding our PDO denied our requested declaration regarding the preemption of the United and LPEA proceedings at the COPUC stating they are not currently preempted. On April 13, 2020, we filed a request for rehearing limited to the issue of preemption of the United and LPEA proceedings at the COPUC related to the contract termination payment number as described in our PDO. Requests for rehearing related to both the PDO and tariff filings have been filed with FERC by other parties. It is not possible to predict if FERC will require us to refund amounts to our customers for sales after the above referenced date, if FERC will approve our current practices regarding use of regulatory assets are just and reasonable, or to estimate any liability associated with this matter. In addition, we cannot predict the outcome of the 206 proceedings, our April  13 request for rehearing or any other request for rehearing filed with FERC.

FERC Fixed Cost Recovery Petition.  On February 17, 2016, we filed a Petition for Declaratory Order with FERC seeking a declaratory order from FERC finding that the fixed cost recovery mechanism in our revised Board policy is consistent with the provisions of the Public Utility Regulatory Policies Act of 1978, as amended and the implementing regulations of FERC. The revised Board policy provides for recovery of the unrecovered fixed costs directly from a Utility Member as a result of that Utility Member purchasing power from a “qualifying facility” in an amount that causes it to exceed the 5 percent limitation on that Utility Member’s self-supply of power pursuant to its wholesale electric service contract, rather than allocating the costs among all of our Utility Members. On June 16, 2016, FERC denied our Petition for Declaratory Order related to the fixed cost recovery mechanism in our revised Board policy. On July 18, 2016, we filed a Request for Rehearing with FERC regarding FERC’s June 16 order. On March 27, 2020, FERC issued an order dismissing our July 18 rehearing request and vacating FERC’s June 16 declaratory order. FERC’s order cited our status as a FERC jurisdictional as the reasoning for vacating its June 16 order and clarified it is as if FERC never rendered an opinion on our 2016 Petition for Declaratory Order.

United Adams District Court Complaint.  On May 4, 2020, United filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court,  2020CV030649, alleging, among other things, that the April 2019 Bylaws

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amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, and that we have breached the wholesale electric service contract with United. We are evaluating the complaint filed by United.

Item 1A.  Risk Factors

The spread of the novel coronavirus COVID-19 could have a material adverse effect on our business.

The global coronavirus (COVID‑19) pandemic has adversely impacted economic activity and conditions worldwide. Measures to control the spread of COVID‑19 have affected the demand for the products and services of many businesses in our Utility Members’ service territories.  There is considerable uncertainty regarding the extent to which COVID‑19 will spread and the extent and duration of measures to try to contain the virus, such as travel bans and restrictions, quarantines, and business and government shutdowns. The full scope and extent of the impacts of COVID‑19 on our operations are unknown.  We continue to monitor the impacts of the pandemic on our workforce, liquidity, capital markets, reliability, cybersecurity, customers, suppliers, and macroeconomic conditions and cannot predict whether COVID‑19 will have a material impact on our business. However, a protracted slowdown of broad sectors of the economy, changes in demand for commodities, particularly oil and gas, or significant changes in legislation or regulatory policy to address the pandemic could result in reduced demand for electricity from our Utility Members and in our region, late payments by our Utility Members, and the inability of our contractors, suppliers and other business partners to fulfill their contractual obligations, any of which could have a material adverse effect on our results of operations, financial condition and cash flows.

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

Exhibit Number	Description of Exhibit
31.1	Rule 13a-14(a)/15d-14(a) Certification, by Duane Highley (Principal Executive Officer).
31.2	Rule 13a-14(a)/15d-14(a) Certification, by Patrick L. Bridges (Principal Financial Officer).
32.1	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Duane Highley (Principal Executive Officer).
32.2	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Patrick L. Bridges (Principal Financial Officer).
95	Mine Safety Disclosure Exhibit.
101	XBRL Interactive Data File.

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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: May 14, 2020	By:	/s/ Duane Highley
		Duane Highley
		Chief Executive Officer
Date: May 14, 2020		/s/ Patrick L. Bridges
		Patrick L. Bridges
		Senior Vice President/Chief Financial Officer (Principal Financial Officer)

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EX-31.1

EXHIBIT 31.1

Rule 13a-14(a)/15d-14(a) Certification, by Duane Highley

(Principal Executive Officer)

I, Duane Highley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tri-State Generation and Transmission Association, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e))and internal controls over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 14, 2020

   /s/ Duane Highley

Duane Highley

Chief Executive Officer

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EX-31.2

EXHIBIT 31.2

Rule 13a-14(a)/15d-14(a) Certification, by Patrick L. Bridges

(Principal Financial Officer)

I, Patrick L. Bridges, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Tri-State Generation and Transmission Association, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 14, 2020

   /s/ Patrick L. Bridges

Patrick L. Bridges

Senior Vice President/Chief Financial Officer

1

EX-32.1

EXHIBIT 32.1

Certification Pursuant to 18 U.S.C. 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q of Tri-State Generation and Transmission Association, Inc. (the “Company”) for the quarterly period ended March 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Duane Highley, the Chief Executive Officer of the Company certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: May 14, 2020

   /s/ Duane Highley

Duane Highley

Chief Executive Officer

1

EX-32.2

EXHIBIT 32.2

Certification Pursuant to 18 U.S.C. 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q of Tri-State Generation and Transmission Association, Inc. (the “Company”) for the quarterly period ended March 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Patrick L. Bridges, the Senior Vice President/Chief Financial Officer of the Company certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: May 14, 2020

  /s/ Patrick L. Bridges

Patrick L. Bridges

Senior Vice President/Chief Financial Officer

1

EX-95

Exhibit 95

Mine Safety and Health Administration Safety Data

Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires issuers that are operators, or that have subsidiaries that is an operator, of a coal or other mine to include in periodic reports filed with the Securities and Exchange Commission certain information relating to citations and orders for violations of standards under the Federal Mine Safety and Health Act of 1977.  The following tables disclose information required under the Dodd-Frank Act from the first quarter of 2020.  The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein. Any such difference may be attributed to the need to update that information on MSHA’s system and/or other factors.

			Section			Total Dollar
			104(d)			Value of	Total Number
Mine Name /		Section	Citations	Section	Section	MSHA	of Mining
MSHA	Section 104	104(b)	and	110(b)(2)	107(a)	Assessments	Related
Identification	S&S Citations	Orders	Orders	Violations	Orders	Proposed	Fatalities
Number	(#)	(#)	(#)	(#)	(#)	(in Thousands, $)	(#)
New Horizon Mine(1) / 0500299	0	0	0	0	0	0	0
Colowyo Mine / 0502962	0	0	0	0	0	0.1	0

		Received
		Notice of
	Received	Potential to
	Notice of	Have Pattern	Legal Actions	Legal Actions	Legal Actions
	Pattern of Violations	of Violations	Pending	Initiated	Resolved
Mine Name /	Under	Under	as of the	During the	During the
MSHA	Section	Section	Three Months Ended	Three Months Ended	Three Months Ended
Identification	104(e)	104(e)	March 31, 2020	March 31, 2020	March 31, 2020
Number	(yes/no)	(yes/no)	(#)	(#)	(#)
New Horizon Mine / 0500299	No	No	0	0	0
Colowyo Mine / 0502962	No	No	0	0	0

The number of legal actions pending before the Federal Mine Safety and Health Review Commission as of March 31, 2020 that fall into each of the following categories is as follows:

						Appeals of
				Complaints for		judges'
	Contests of	Contests of		discharge,		decisions or
	Citations/	Proposed	Complaints for	discrimination,	Applications for	orders to
	Orders	Penalties	compensation	or interference	temporary relief	FMSHRC
Mine Name /	referenced in	referenced in	referenced in	referenced in	referenced in	referenced in
MSHA	Subpart B,	Subpart C,	Subpart D,	Subpart E,	Subpart F	Subpart H
Identification	29CFR	29CFR	29CFR	29CFR	29CFR	29CFR
Number	Part 2700	Part 2700	Part 2700	Part 2700	Part 2700	Part 2700
New Horizon Mine / 0500299	0	0	0	0	0	0
Colowyo Mine / 0502962	0	0	0	0	0	0

(1)  The New Horizon Mine is working to complete final reclamation and the mine data retrieval system maintained by MSHA lists the New Horizon Mine status as abandoned.

1

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INVESTMENTS IN AND ADVANCES TO COAL MINES (Tables)

3 Months Ended

Mar. 31, 2020

INVESTMENTS IN AND ADVANCES TO COAL MINES

Schedule of investments in and advances to coal mines

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

	March 31,		December 31,
	2020		2019
Investment in Trapper Mine	$	16,014	$	15,881
Advances to Dry Fork Mine		3,675		3,800
Investments in and advances to coal mines	$	19,689	$	19,681

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LEGAL

3 Months Ended

Mar. 31, 2020

LEGAL

LEGAL

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 notified us and the other entity of its intent to arbitrate in accordance with the agreement and claimed damages caused by the alleged breach of approximately $6.9 million, plus interest, attorney fees, and any future damages. The other entity filed a cross-claim against us claiming we are responsible for such entity’s share of any damages. The matter was scheduled for arbitration to commence in January 2020. The arbitration was cancelled and the parties continue to discuss a resolution of this matter. It is not possible to predict whether this matter will be resolved without arbitration or whether we will incur any liability in connection with this matter.

At our July 2019 Board meeting, our Board authorized us to take action to place us under wholesale rate regulation by FERC. On September 3, 2019, a membership agreement with a Non-Utility Member, MIECO, Inc., became effective. The admission of the new Non-Utility 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 (“FPA”). During the week of December 23, 2019, we filed our tariff filings, including our stated rate cost of service filing, market based rate authorization, and transmission Open Access Transmission Tariff. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order (“PDO”) with FERC asking FERC to confirm our jurisdiction under the FPA and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission (“COPUC”) to address any rate related issues. Numerous parties filed interventions or protests with FERC. Some of the interveners and protestors, including some of our Utility Members and the COPUC alleged that we are not FERC jurisdictional and are still exempt from FERC wholesale rate regulation pursuant to the FPA. On March 20, 2020, FERC issued orders regarding our PDO and our tariff filings. FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC did provide that FERC will not require refunds for our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC did not impose any civil penalties on us. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered a 206 proceeding to determine the justness and reasonableness of our rates and wholesale electric service contracts. The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. The settlement proceedings are continuing. Any refunds to the applicable tariff rates would only apply to after the above referenced dates. On April 13, 2020, we filed a request for rehearing limited to the issue of preemption of the COPUC related to the contract termination payment number as described in our PDO. Requests for rehearing related to both the PDO and tariff filings have been filed with FERC by other parties. It is not possible to predict if FERC will require us to refund amounts to our customers for sales after the above referenced date, if FERC will approve our current practices regarding use of regulatory assets are just and reasonable, or to estimate any liability associated with this matter. In addition, we cannot predict the outcome of the 206 proceedings, our April 13 request for rehearing or any other request for rehearing filed with FERC.

On May 4, 2020, United Power, Inc. (“United”) filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court alleging, among other things, that the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, and that we have breached the wholesale electric service contract with United. We are evaluating the complaint filed by United.

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INCOME TAXES

3 Months Ended

Mar. 31, 2020

INCOME TAXES

INCOME TAXES

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. This liability method is included in our rate filling 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 $0.2 million for the three months ended March 31, 2020 and $0.1 million for the comparable period in 2019. These income tax benefits are due to an alternative minimum tax credit refund.

During the three months ended March 31, 2020, we recorded a decrease in our deferred tax asset valuation allowance due to the deferred tax treatment of an abandonment loss. We concluded that a valuation allowance of $19.0 million was more likely than not needed based on the expected realization of deferred tax assets for the period ended March 31, 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.

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PRESENTATION OF FINANCIAL INFORMATION (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2020 USD ($) item class facility
Jointly owned facilities
Number of jointly owned facilities | facility	2
Electric plant in service	$ 885,213
Accumulated depreciation	549,105
Construction work in progress	$ 4,069
Member information
Number of classes of members | class	3
Yampa
Jointly owned facilities
Tri-State share (as a percent)	24.00%
Electric plant in service	$ 396,334
Accumulated depreciation	249,757
Construction work in progress	$ 201
MBPP
Jointly owned facilities
Tri-State share (as a percent)	27.13%
Electric plant in service	$ 488,879
Accumulated depreciation	299,348
Construction work in progress	$ 3,868
Class A Members
Member information
Number of members | item	43
Class B Members
Member information
Number of classes of members | class	0
Non Utility Members
Member information
Number of members | item	3

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Mar. 10, 2020	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2017
Cash, cash equivalents, restricted cash and investments
Cash and cash equivalents	$ 180,682		$ 83,070
Restricted cash and investments - current	188		182
Restricted cash and investments - noncurrent	4,967		30,516
Cash, cash equivalents and restricted cash and investments	185,837		113,768	$ 125,129	$ 127,590
Internally restricted cash	$ 100		$ 25,500
Internally restricted cash released		$ 25,500

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LONG-TERM DEBT - Other Information (Details)	3 Months Ended
	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Debt
Long-term debt	$ 3,303,207,000	$ 3,144,906,000
Unsecured debt
Number of unsecured debt instruments	1
Unsecured notes	$ 25,300,000
Credit facility information
Outstanding borrowings	3,324,478,000	$ 3,166,472,000
Proceeds from debt draw	$ 200,000,000
Equity to capitalization ratio (ECR) requirement	18.00%
Other Than Long Term Debt
Credit facility information
Debt service ratio (DSR) requirement	1.02
Other
Credit facility information
Debt service ratio (DSR) requirement	1.10
2018 Revolving Credit Agreement
Credit facility information
Maximum borrowing capacity	$ 650,000,000
Available borrowing capacity	285,000,000
Outstanding borrowings	200,000,000
2018 Revolving Credit Agreement | Commercial Paper
Credit facility information
Available borrowing capacity	285,000,000
Swingline
Credit facility information
Maximum borrowing capacity	100,000,000
Letter of Credit
Credit facility information
Maximum borrowing capacity	75,000,000
Commercial Paper
Credit facility information
Maximum borrowing capacity	500,000,000
Outstanding borrowings	$ 165,000,000

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LEGAL - Legal (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020 USD ($)
Long-term Transmission Agreement Dispute
Damages sought	$ 6.9

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LEASES - Leasing Arrangements as Lessor (Details) $ in Millions	3 Months Ended
	Mar. 31, 2020 USD ($) MW	Mar. 31, 2019 USD ($)
Lease revenue | $	$ 1.6	$ 4.3
J. M. Shafer Generating Station
Megawatt usage	272
J. M. Shafer Generating Station | Third Party
Megawatt usage	122

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REVENUE - Non-member (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Disaggregation of revenue
Other	$ 10,890	$ 14,256
Revenues	319,466	339,917
Non-member electric sales and other operating revenue
Disaggregation of revenue
Revenues	26,703	40,986
Non-member electric sales
Disaggregation of revenue
Revenue from contract with customer	15,813	26,730
Non-member electric sales | Long-term contracts
Disaggregation of revenue
Revenue from contract with customer	12,144	11,682
Non-member electric sales | Short-term contracts
Disaggregation of revenue
Revenue from contract with customer	3,669	15,048
Other
Disaggregation of revenue
Other	$ 10,890	$ 14,256

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EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Actuarial Gains and Losses (Details) - Postretirement Medical Benefit Plans $ in Thousands	3 Months Ended
	Mar. 31, 2020 USD ($)
Net unrecognized actuarial gains and losses
Amounts included in accumulated other comprehensive income at beginning of period	$ (1,387)
Amortization of actuarial (gain) loss into income	11
Amortization of prior service credit into other income	(20)
Amounts included in accumulated other comprehensive income at end of period	$ (1,396)

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SHORT-TERM BORROWINGS (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Short-term borrowings
Amount outstanding	$ 164,723	$ 252,323
Commercial Paper
Short-term borrowings
Amount outstanding	$ 164,723	$ 252,323
Weighted average interest rate	1.83%	1.88%
Commercial Paper | Maximum
Short-term borrowings
Maximum amount per commercial paper sublimit	$ 500,000
Term of issuance	397 days
2018 Revolving Credit Agreement
Short-term borrowings
Available borrowing capacity	$ 285,000
2018 Revolving Credit Agreement | Commercial Paper
Short-term borrowings
Available borrowing capacity	$ 285,000

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Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Consolidated Statements of Comprehensive Income
Net margins including noncontrolling interest	$ (3,291)	$ 8,006
Other comprehensive income (loss):
Amortization of actuarial (gain) loss on postretirement benefit obligation included in net margin	933	33
Unrecognized prior service cost	(7,373)	(214)
Other comprehensive income (loss)	(6,440)	(181)
Comprehensive income including noncontrolling interest	(9,731)	7,825
Net comprehensive income attributable to noncontrolling interest	(1,319)	(1,017)
Comprehensive income attributable to the Association	$ (11,050)	$ 6,808

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ACCOUNTING FOR RATE REGULATION

3 Months Ended

Mar. 31, 2020

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION

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):

	March 31,		December 31,
	2020		2019
Regulatory assets
Deferred income tax expense (1)	$	33,970	$	58,937
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)		83,142		83,714
Goodwill – J.M. Shafer (3)		48,433		49,145
Goodwill – Colowyo Coal (4)		36,936		37,194
Deferred debt prepayment transaction costs (5)		138,774		140,931
Deferred Holcomb expansion impairment loss (6)		92,325		93,494
Unrecovered plant (7)		299,204		33,864
Total regulatory assets		732,784		497,279
Regulatory liabilities
Interest rate swap - realized gain (8)		3,626		3,744
Deferred revenues (9)		75,853		75,853
Membership withdrawal (10)		42,572		42,572
Total regulatory liabilities		122,051		122,169
Net regulatory asset	$	610,733	$	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.

(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 other operating expenses 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. In May 2020, we filed an accounting filing with FERC to request regulatory treatment for the Escalante Generating Station impaired loss and believe it is probable that FERC will allow us to recover the costs in our rates. If required, we will make a Section 205 filing under the Federal Power Act in connection with any future rate change resulting from the decommission of the Escalante Generating Station. 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 recorded in connection with the withdrawal of a former Utility Member from membership in us. This deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in other income in future periods.    

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ASSET RETIREMENT OBLIGATIONS

3 Months Ended

Mar. 31, 2020

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

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

	Three Months Ended
		March 31,
		2020
Obligations at beginning of period		$	78,914
Liabilities incurred			—
Liabilities settled			—
Accretion expense			629
Change in cash flow estimate			3,337
Total obligations at end of period		$	82,880
Less current obligations at end of period			(1,802)
Long-term obligations at end of period		$	81,078

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.

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CONTRACT ASSETS AND CONTRACT LIABILITIES

3 Months Ended

Mar. 31, 2020

CONTRACT ASSETS AND CONTRACT LIABILITIES

CONTRACT ASSETS AND CONTRACT LIABILITIES

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 three months ended March 31, 2020, we recognized $0.3 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):

	March 31,		December 31,
	2020		2019
Accounts receivable - Utility Members	$	97,901	$	105,371
Other accounts receivable - trade:
Non-member electric sales		3,918		4,727
Other		16,601		20,628
Total other accounts receivable - trade		20,519		25,355
Other accounts receivable - nontrade		693		2,684
Total other accounts receivable	$	21,212	$	28,039
Contract liabilities (unearned revenue)	$	6,825	$	7,041

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OTHER DEFERRED CHARGES (Tables)

3 Months Ended

Mar. 31, 2020

OTHER DEFERRED CHARGES.

Schedule of Other Deferred Charges

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

	March 31,		December 31,
	2020		2019
Preliminary surveys and investigations	$	22,167	$	21,261
Advances to operating agents of jointly owned facilities		10,197		3,917
Operating lease right-of-use assets		8,327		7,622
Other		15,431		9,872
Total other deferred charges	$	56,122	$	42,672

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)

3 Months Ended

Mar. 31, 2020

OTHER DEFERRED CREDITS AND OTHER LIABILITIES

Schedule of 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):

	March 31,		December 31,
	2020		2019
Transmission easements	$	20,235	$	20,549
Operating lease liabilities - noncurrent		1,921		1,846
Contract liabilities (unearned revenue) - noncurrent		4,123		4,217
Customer deposits		2,251		3,015
Financial liabilities - reclamation		12,070		12,091
Other		13,795		14,681
Total other deferred credits and other liabilities	$	54,395	$	56,399

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FAIR VALUE (Tables)

3 Months Ended

Mar. 31, 2020

Marketable securities

FAIR VALUE

Schedule of carrying amounts and fair values of assets and liabilities

The cost and fair values of our marketable securities are as follows (dollars in thousands):

	March 31, 2020				December 31, 2019
			Estimated				Estimated
	Cost		Fair Value		Cost		Fair Value
Marketable securities	$	528	$	400	$	715	$	654

Debt

FAIR VALUE

Schedule of carrying amounts and fair values of assets and liabilities

The principal amounts and fair values of our debt are as follows (dollars in thousands):

	March 31, 2020				December 31, 2019
	Principal		Estimated		Principal		Estimated
	Amount		Fair Value		Amount		Fair Value
Total debt	$	3,324,478	$	4,140,708	$	3,166,472	$	3,608,341

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EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan, Obligations (Details) - NRECA Executive Benefit Restoration Plan $ in Thousands	3 Months Ended
	Mar. 31, 2020 USD ($)
Defined Benefit Plans
Beginning of period	$ 674
Service cost	206
Interest cost	291
Plan amendments - prior service cost	5,218
Actuarial loss	2,155
End of period	$ 8,544
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%

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ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Aggregate carrying amounts of asset retirement obligations
Asset retirement obligation at beginning of period	$ 78,914
Accretion expense	629
Change in cash flow estimate	3,337
Asset retirement obligation at end of period	82,880
Less current asset retirement obligations	(1,802)	$ (2,460)
Long-term obligations at end of period	$ 81,078

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INCOME TAXES (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2018
INCOME TAXES
Income tax benefit	$ 209	$ 77	$ 100
Valuation allowance	$ 19,000

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INVESTMENTS IN OTHER ASSOCIATIONS

3 Months Ended

Mar. 31, 2020

INVESTMENTS IN OTHER ASSOCIATIONS

INVESTMENTS IN OTHER ASSOCIATIONS

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):

	March 31,		December 31,
	2020		2019
Basin Electric Power Cooperative	$	117,368	$	117,368
National Rural Utilities Cooperative Finance Corporation - patronage capital		11,761		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.		2,193		2,409
Other		4,214		4,253
Investments in other associations	$	162,562	$	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 three months ended March 31, 2020 or during 2019.

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Consolidated Statements of Equity - USD ($) $ in Thousands	Patronage capital	Accumulated other comprehensive income (loss)	Noncontrolling interest	Total
Equity at beginning of period at Dec. 31, 2018	$ 1,015,754	$ 375	$ 110,169
Change in Equity
Net margins attributable to the Association	6,989			$ 6,989
Amortization of prior period cost				33
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net margin		33
Unrecognized prior service cost		(214)		(214)
Net comprehensive income attributable to noncontrolling interest			1,017	1,017
Equity distribution to noncontrolling interest			(1,454)
Equity at end of period at Mar. 31, 2019	1,022,743	194	109,732	1,132,669
Equity at beginning of period at Dec. 31, 2019	1,031,063	(1,518)	111,717	1,141,262
Change in Equity
Net margins attributable to the Association	(4,610)			(4,610)
Amortization of prior period cost				933
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net margin		933
Unrecognized prior service cost		(7,373)		(7,373)
Net comprehensive income attributable to noncontrolling interest			1,319	1,319
Equity distribution to noncontrolling interest			(1,268)
Equity at end of period at Mar. 31, 2020	$ 1,026,453	$ (7,958)	$ 111,768	$ 1,130,263

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Document and Entity Information	3 Months Ended
	Mar. 31, 2020 shares
Document and Entity Information
Document Type	10-Q
Document Period End Date	Mar. 31, 2020
Entity Registrant Name	Tri-State Generation & Transmission Association, Inc.
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	0
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001637880
Amendment Flag	false

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES

3 Months Ended

Mar. 31, 2020

OTHER DEFERRED CREDITS AND OTHER LIABILITIES

OTHER DEFERRED CREDITS AND OTHER LIABILITIES

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):

	March 31,		December 31,
	2020		2019
Transmission easements	$	20,235	$	20,549
Operating lease liabilities - noncurrent		1,921		1,846
Contract liabilities (unearned revenue) - noncurrent		4,123		4,217
Customer deposits		2,251		3,015
Financial liabilities - reclamation		12,070		12,091
Other		13,795		14,681
Total other deferred credits and other liabilities	$	54,395	$	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 $20.2 and $20.5 million as of March 31, 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.

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.

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OTHER DEFERRED CHARGES

3 Months Ended

Mar. 31, 2020

OTHER DEFERRED CHARGES.

OTHER DEFERRED CHARGES

NOTE 7 – OTHER DEFERRED CHARGES

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

	March 31,		December 31,
	2020		2019
Preliminary surveys and investigations	$	22,167	$	21,261
Advances to operating agents of jointly owned facilities		10,197		3,917
Operating lease right-of-use assets		8,327		7,622
Other		15,431		9,872
Total other deferred charges	$	56,122	$	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.

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LEASES (Tables)

3 Months Ended

Mar. 31, 2020

LEASES

Schedule of lease components

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

	March 31,
	2020
Operating leases
Operating lease right-of-use assets	$	9,312
Less: Accumulated amortization		(985)
Net operating lease right-of-use assets	$	8,327
Operating lease liabilities - current	$	(6,355)
Operating lease liabilities - noncurrent		(1,921)
Total operating lease liabilities	$	(8,276)
Operating leases
Weighted average remaining lease term (years)		9.3
Weighted average discount rate		3.75%

Schedule of expected minimum lease commitments under operating leases

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

Year 1	$	6,430
Year 2		526
Year 3		364
Year 4		334
Year 5		284
Thereafter		779
Total lease payments	$	8,717
Less imputed interest		(441)
Total	$	8,276

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CONTRACT ASSETS AND CONTRACT LIABILITIES (Tables)

3 Months Ended

Mar. 31, 2020

CONTRACT ASSETS AND CONTRACT LIABILITIES

Schedule of contract assets and liabilities

	March 31,		December 31,
	2020		2019
Accounts receivable - Utility Members	$	97,901	$	105,371
Other accounts receivable - trade:
Non-member electric sales		3,918		4,727
Other		16,601		20,628
Total other accounts receivable - trade		20,519		25,355
Other accounts receivable - nontrade		693		2,684
Total other accounts receivable	$	21,212	$	28,039
Contract liabilities (unearned revenue)	$	6,825	$	7,041

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ASSET RETIREMENT OBLIGATIONS (Tables)

3 Months Ended

Mar. 31, 2020

ASSET RETIREMENT OBLIGATION

Schedule of Asset Retirement Obligations

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

	Three Months Ended
		March 31,
		2020
Obligations at beginning of period		$	78,914
Liabilities incurred			—
Liabilities settled			—
Accretion expense			629
Change in cash flow estimate			3,337
Total obligations at end of period		$	82,880
Less current obligations at end of period			(1,802)
Long-term obligations at end of period		$	81,078

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PRESENTATION OF FINANCIAL INFORMATION (Tables)

3 Months Ended

Mar. 31, 2020

PRESENTATION OF FINANCIAL INFORMATION

Schedule of jointly owned facilities

Our share in each jointly owned facility is as follows as of March 31, 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	%	$	396,334	$	249,757	$	201
MBPP - Laramie River Station	27.13	%		488,879		299,348		3,868
Total			$	885,213	$	549,105	$	4,069

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LEASES

3 Months Ended

Mar. 31, 2020

LEASES

LEASES

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 $0.9 million for the three months ended March 31, 2020 and $1.8 million for the comparable period in 2019. Rent expense is included in operating expenses on our consolidated statements of operations. As of March 31, 2020, there were no arrangements accounted for as finance leases.

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

	March 31,
	2020
Operating leases
Operating lease right-of-use assets	$	9,312
Less: Accumulated amortization		(985)
Net operating lease right-of-use assets	$	8,327
Operating lease liabilities - current	$	(6,355)
Operating lease liabilities - noncurrent		(1,921)
Total operating lease liabilities	$	(8,276)
Operating leases
Weighted average remaining lease term (years)		9.3
Weighted average discount rate		3.75%

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

Year 1	$	6,430
Year 2		526
Year 3		364
Year 4		334
Year 5		284
Thereafter		779
Total lease payments	$	8,717
Less imputed interest		(441)
Total	$	8,276

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 $4.3 million for the three months ended March 31, 2020 and 2019, respectively, 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.

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Tables)

3 Months Ended

Mar. 31, 2020

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

Schedule of cash, cash equivalents and restricted cash and investments

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):

	March 31,		December 31,
	2020		2019
Cash and cash equivalents	$	180,682	$	83,070
Restricted cash and investments - current		188		182
Restricted cash and investments - noncurrent		4,967		30,516
Cash, cash equivalents and restricted cash and investments	$	185,837	$	113,768

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LONG-TERM DEBT - Components (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Long-term debt, components
Total debt	$ 3,324,478	$ 3,166,472
Less debt issuance costs	(26,810)	(27,412)
Less debt discounts	(9,846)	(9,906)
Plus debt premiums	15,385	15,752
Total debt adjusted for debt issuance costs, discounts and premiums	3,303,207	3,144,906
Less current maturities	(85,636)	(81,555)
Long-term debt	$ 3,217,571	$ 3,063,351

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VARIABLE INTEREST ENTITIES (Tables)

3 Months Ended

Mar. 31, 2020

VARIABLE INTEREST ENTITIES

Schedule of consolidated variable interest entities

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

	March 31,		December 31,
	2020		2019
Net electric plant	$	771,876	$	776,411
Noncontrolling interest		111,768		111,717
Long-term debt		343,313		380,867
Accrued interest		3,977		11,050

Our consolidated statements of operations include the following Springerville Partnership expenses for the three months ended March 31, 2020 and 2019 (dollars in thousands):

		March 31,		March 31,
	2020		2019
Depreciation, amortization and depletion	$	4,534	$	4,534
Interest		5,861		6,831

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INVESTMENTS IN AND ADVANCES TO COAL MINES (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Investments in and advances to coal mines
Investments in and advances to coal mines	$ 19,689	$ 19,681
Trapper Mining
Investments in and advances to coal mines
Investment in coal mine	16,014	15,881
Dry Fork Mine
Investments in and advances to coal mines
Advances	$ 3,675	$ 3,800

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FAIR VALUE (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Fair value:
Regulatory liabilities	$ 122,051	$ 122,169
Principal Amount
Fair value:
Marketable securities	528	715
Long-term debt	3,324,478	3,166,472
Estimated Fair Value
Fair value:
Cash and cash equivalents	114,800	79,000
Estimated Fair Value | Level 2
Fair value:
Long-term debt	4,140,708	3,608,341
Estimated Fair Value | Recurring | Level 1
Fair value:
Marketable securities	$ 400	$ 654

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PRESENTATION OF FINANCIAL INFORMATION

3 Months Ended

Mar. 31, 2020

PRESENTATION OF FINANCIAL INFORMATION

PRESENTATION OF FINANCIAL INFORMATION

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 March 31, 2020, results of operations for the three months ended March 31, 2020 and 2019, and cash flows for the three months ended March 31, 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 Class C - non-utility members. For our Class A members, we provide electric power to our forty-three electric distribution member systems (“Class A Member(s)”) 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.

Our share in each jointly owned facility is as follows as of March 31, 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	%	$	396,334	$	249,757	$	201
MBPP - Laramie River Station	27.13	%		488,879		299,348		3,868
Total			$	885,213	$	549,105	$	4,069

Recently Adopted Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses in Financial Instruments. FASB issued subsequent amendments to the initial guidance in November 2018 with ASU 2018-19, in April 2019 with ASU 2019-04, and in May 2019 with ASU 2019-05. The ASU amends the guidance on the impairment of financial instruments and adds an impairment model, known as the current expected credit loss (“CECL”) model. The CECL model requires an entity to recognize its current estimate of all expected credit losses, rather than incurred losses, and applies to trade receivables and other receivables. The CECL model is designed to capture expected credit losses through the establishment of an allowance account, which will be presented as an offset to the amortized cost basis of the related financial asset. The new guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and is applied using the modified-retrospective approach. We have evaluated the impact of this ASU and have adopted this standard for the fiscal year beginning January 1, 2020. The adoption of this standard did not have an impact on our consolidated statements of financial position or consolidated statements of operations.

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Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating revenues
Other	$ 10,890	$ 14,256
Operating revenues	319,466	339,917
Operating expenses
Purchased power	71,015	70,956
Fuel	61,069	85,149
Production	43,188	47,761
Transmission	41,540	39,142
General and administrative	16,215	10,813
Depreciation, amortization and depletion	47,024	38,145
Coal mining	2,734	3,596
Other	7,683	3,838
Operating expenses	290,468	299,400
Operating margins	28,998	40,517
Other income
Interest	1,305	1,415
Capital credits from cooperatives	3,353	2,997
Other	(250)	1,281
Total other income	4,408	5,693
Interest expense
Interest	38,867	40,652
Interest charged during construction	(1,961)	(2,371)
Interest expense, net of amounts capitalized	36,906	38,281
Income tax benefit	(209)	(77)
Net margins including noncontrolling interest	(3,291)	8,006
Net margin attributable to noncontrolling interest	(1,319)	(1,017)
Net margins attributable to the Association	(4,610)	6,989
Member electric sales
Operating revenues
Operating revenues	292,763	298,931
Non-member electric sales
Operating revenues
Operating revenues	$ 15,813	$ 26,730

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REVENUE - Member (Details)	3 Months Ended
	Mar. 31, 2020 item customer
Member electric sales
Number of billing components of Class A rate schedule for electric power sales to Members | item	3
Number of demand rates | item	2
Member Contracts Extending Through 2050
Member electric sales
Number of contracts | customer	42
Member Contracts Extending Through 2040
Member electric sales
Number of contracts | customer	1

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EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Obligations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2020 USD ($) plan
Medical Plans
Postretirement medical benefit and postemployment medical benefit obligations
End of period	$ 10,644
Postretirement Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Beginning of period	10,195
Service cost	141
Interest cost	88
Benefit payments (net of contributions by participants)	(155)
End of period	$ 10,269
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%
Postemployment Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
End of period	$ 375
Non-bargaining unit employees | Medical Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Non-bargaining unit employees | Medical Plans | Maximum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	65 years
Non-bargaining unit employees | Postretirement Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	2
Non-bargaining unit employees | Postretirement Medical Benefit Plans | Minimum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	55 years
Non-bargaining unit employees | Postemployment Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3

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LONG-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2020

LONG-TERM DEBT.

Schedule of long-term debt

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

	March 31,		December 31,
	2020		2019
Total debt	$	3,324,478		3,166,472
Less debt issuance costs		(26,810)		(27,412)
Less debt discounts		(9,846)		(9,906)
Plus debt premiums		15,385		15,752
Total debt adjusted for debt issuance costs, discounts and premiums		3,303,207		3,144,906
Less current maturities		(85,636)		(81,555)
Long-term debt	$	3,217,571	$	3,063,351

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EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2020

Postretirement Medical Benefit Plans

Schedule of employee benefit plan obligations

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):

	March 31,
	2020
Postretirement medical benefit obligation at beginning of period	$	10,195
Service cost		141
Interest cost		88
Benefit payments (net of contributions by participants)		(155)
Postretirement medical benefit obligation at end of period	$	10,269
Postemployment medical benefit obligation at end of period		375
Total postretirement and postemployment medical obligations at end of period	$	10,644

Schedule of the net unrecognized actuarial gains and losses related to employee benefit plan obligations

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):

	2020
Amounts included in accumulated other comprehensive income at beginning of period	$	(1,387)
Amortization of actuarial (gain) loss into income		11
Amortization of prior service credit into other income		(20)
Amounts included in accumulated other comprehensive income at end of period	$	(1,396)

NRECA Executive Benefit Restoration Plan

Schedule of employee benefit plan obligations

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):

	March 31,
	2020
Executive benefit restoration obligation at beginning of period	$	674
Service cost		206
Interest cost		291
Plan amendments - prior service cost		5,218
Actuarial loss		2,155
Executive benefit restoration at end of period	$	8,544

Schedule of the net unrecognized actuarial gains and losses related to employee benefit plan obligations

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):

	March 31,
	2020
Amounts included in accumulated other comprehensive income at beginning of period	$	(130)
Plan amendments - prior service cost		(5,218)
Amortization of prior service cost into other income		942
Unrecognized actuarial loss		(2,155)
Amounts included in accumulated other comprehensive income at end of period	$	(6,561)

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REVENUE

3 Months Ended

Mar. 31, 2020

REVENUE

REVENUE

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 Utility Members extend through 2050 for 42 Utility Members and 2040 for the remaining Utility Member.

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.

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 March 31,
	2020		2019
Non-member electric sales:
Long-term contracts	$	12,144	$	11,682
Short-term contracts		3,669		15,048
Other		10,890		14,256
Total non-member electric sales and other operating revenue	$	26,703	$	40,986

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 was issued). 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.

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SHORT-TERM BORROWINGS

3 Months Ended

Mar. 31, 2020

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS

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):

	March 31,			December 31,
	2020			2019
Commercial paper outstanding, net of discounts	$	164,723		$	252,323
Weighted average interest rate		1.83	%		1.88	%

At March 31, 2020,  $285.0 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 8 – Long-Term Debt.

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS

3 Months Ended

Mar. 31, 2020

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS

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):

	March 31,		December 31,
	2020		2019
Cash and cash equivalents	$	180,682	$	83,070
Restricted cash and investments - current		188		182
Restricted cash and investments - noncurrent		4,967		30,516
Cash, cash equivalents and restricted cash and investments	$	185,837	$	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 has internally restricted cash in the amount of $0.1 million and $25.5 million as of March 31, 2020 and December 31, 2019, respectively, which is 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 as of December 31, 2019 related to deferred revenue in response to volatile market conditions.

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INVESTMENTS IN OTHER ASSOCIATIONS (Tables)

3 Months Ended

Mar. 31, 2020

INVESTMENTS IN OTHER ASSOCIATIONS

Schedule of investments in other associations

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

	March 31,		December 31,
	2020		2019
Basin Electric Power Cooperative	$	117,368	$	117,368
National Rural Utilities Cooperative Finance Corporation - patronage capital		11,761		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.		2,193		2,409
Other		4,214		4,253
Investments in other associations	$	162,562	$	161,945

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VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2020

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

NOTE 17 – VARIABLE INTEREST ENTITIES

The following is a description of our financial interests in variable interest entities that weconsider 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):

	March 31,		December 31,
	2020		2019
Net electric plant	$	771,876	$	776,411
Noncontrolling interest		111,768		111,717
Long-term debt		343,313		380,867
Accrued interest		3,977		11,050

Our consolidated statements of operations include the following Springerville Partnership expenses for the three months ended March 31, 2020 and 2019 (dollars in thousands):

		March 31,		March 31,
	2020		2019
Depreciation, amortization and depletion	$	4,534	$	4,534
Interest		5,861		6,831

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 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 $2.2 million at March 31, 2020 and $2.4 million at December 31, 2019 and is included in investments in other associations.

Western Fuels – Wyoming (“WFW”):  WFW, the owner and operator of the Dry Fork Mine in Gillette, Wyoming, 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 March 31, 2020 and December 31, 2019 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 $16.0 million at March 31, 2020 and $15.9 million at December 31, 2019.

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VARIABLE INTEREST ENTITIES - Unconsolidated Entities (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Western Fuels Association | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in unconsolidated VIE	$ 2.2	$ 2.4
WFW | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in unconsolidated VIE	$ 0.1	0.1
MBPP
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	27.13%
WFW | Western Fuels Association | Class AA shares
Unconsolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%
WFW | Western Fuels Association | Class BB Shares
Unconsolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	75.00%
WFW | MBPP | Class BB Shares
Unconsolidated Variable Interest Entities
Ownership interest held by noncontrolling interest (as a percent)	25.00%
MBPP | Unconsolidated Variable Interest Entity - not primary beneficiary
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	27.13%
Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	26.57%
Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments In and Advances To Coal Mines [Member]
Unconsolidated Variable Interest Entities
Investment in coal mine	$ 16.0	$ 15.9

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LEASES - Future Minimum Lease Commitments (Details) $ in Thousands	Mar. 31, 2020 USD ($)
Future expected minimum lease commitments under operating leases
Year 1	$ 6,430
Year 2	526
Year 3	364
Year 4	334
Year 5	284
Thereafter	779
Total lease payments	8,717
Less imputed interest	(441)
Total	$ 8,276

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ACCOUNTING FOR RATE REGULATION (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Oct. 31, 2017	Mar. 31, 2020	Sep. 30, 2019	Dec. 31, 2019
Regulatory assets and liabilities
Regulatory assets		$ 732,784		$ 497,279
Regulatory liabilities		122,051		122,169
Net regulatory asset		610,733		375,110
Impairment loss		259,761
Interest rate swaps, realized gain
Regulatory assets and liabilities
Regulatory liabilities		3,626		3,744
Proceeds from settlement of interest rate swaps	$ 4,600
Deferred non-member electric sales
Regulatory assets and liabilities
Regulatory liabilities		75,853		75,853
Deferred revenue from membership withdrawal
Regulatory assets and liabilities
Regulatory liabilities		$ 42,572		42,572
First Mortgage Obligations, Series 2017A , Tranche 1, 3.34%, due through 2029
Regulatory assets and liabilities
Term of issuance		12 years
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets		$ 33,970		58,937
Deferred prepaid lease expense | Springerville Unit 3 Lease
Regulatory assets and liabilities
Regulatory assets		83,142		83,714
Annual amortization expense		$ 2,300
Amortization period		47 years
Goodwill | TCP
Regulatory assets and liabilities
Regulatory assets		$ 48,433		49,145
Annual amortization expense		$ 2,800
Amortization period		25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets		$ 36,936		37,194
Annual amortization expense		$ 1,000
Amortization period		44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets		$ 138,774		140,931
Annual amortization expense		$ 8,600
Amortization period		21 years 4 months 24 days
Deferred impairment loss | Unrecovered Plants
Regulatory assets and liabilities
Regulatory assets		$ 299,204		33,864
Deferred impairment loss | Nucla Generating Station
Regulatory assets and liabilities
Impairment loss			$ 37,100
Amortization period		3 years 3 months 18 days
Deferred impairment loss | Escalante Generating Station
Regulatory assets and liabilities
Impairment loss		$ 268,200
Deferred impairment loss | Holcomb Expansion
Regulatory assets and liabilities
Regulatory assets		92,325		$ 93,494
Annual amortization expense		$ 4,700
Amortization period		20 years

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CONTRACT ASSETS AND CONTRACT LIABILITIES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Accounts receivable
Accounts receivable—Members	$ 97,901	$ 105,371
Other accounts receivable	21,212	28,039
Contract liabilities
Contract liabilities (unearned revenue)	6,825	7,041
Other accounts receivable - trade
Accounts receivable
Other accounts receivable	20,519	25,355
Other accounts receivable - trade | Non-member electric sales
Accounts receivable
Other accounts receivable	3,918	4,727
Other accounts receivable - trade | Other
Accounts receivable
Other accounts receivable	16,601	20,628
Other accounts receivable, non-trade
Accounts receivable
Other accounts receivable	693	$ 2,684
Other operating revenue
Contract liabilities
Contract liabilities recognized	$ 300

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ACCOUNTING FOR RATE REGULATION (Tables)

3 Months Ended

Mar. 31, 2020

ACCOUNTING FOR RATE REGULATION

Schedule of regulatory assets and liabilities

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

	March 31,		December 31,
	2020		2019
Regulatory assets
Deferred income tax expense (1)	$	33,970	$	58,937
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)		83,142		83,714
Goodwill – J.M. Shafer (3)		48,433		49,145
Goodwill – Colowyo Coal (4)		36,936		37,194
Deferred debt prepayment transaction costs (5)		138,774		140,931
Deferred Holcomb expansion impairment loss (6)		92,325		93,494
Unrecovered plant (7)		299,204		33,864
Total regulatory assets		732,784		497,279
Regulatory liabilities
Interest rate swap - realized gain (8)		3,626		3,744
Deferred revenues (9)		75,853		75,853
Membership withdrawal (10)		42,572		42,572
Total regulatory liabilities		122,051		122,169
Net regulatory asset	$	610,733	$	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.

(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 other operating expenses 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. In May 2020, we filed an accounting filing with FERC to request regulatory treatment for the Escalante Generating Station impaired loss and believe it is probable that FERC will allow us to recover the costs in our rates. If required, we will make a Section 205 filing under the Federal Power Act in connection with any future rate change resulting from the decommission of the Escalante Generating Station. 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.

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

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FAIR VALUE

3 Months Ended

Mar. 31, 2020

FAIR VALUE

FAIR VALUE

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 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):

	March 31, 2020				December 31, 2019
			Estimated				Estimated
	Cost		Fair Value		Cost		Fair Value
Marketable securities	$	528	$	400	$	715	$	654

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 $114.8 million as of March 31, 2020 and $79.0 million as of December 31, 2019.

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):

	March 31, 2020				December 31, 2019
	Principal		Estimated		Principal		Estimated
	Amount		Fair Value		Amount		Fair Value
Total debt	$	3,324,478	$	4,140,708	$	3,166,472	$	3,608,341

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VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Consolidated Variable Interest Entities
Net electric plant	$ 3,355,091		$ 3,613,846
Noncontrolling interest	111,768		111,717
Long-term debt	3,217,571		3,063,351
Accrued interest	47,037		29,716
Interest	$ 36,906	$ 38,281
Springerville Partnership
Consolidated Variable Interest Entities
Equity interest (as a percent)	51.00%
General partner interest (as a percent)	1.00%
Springerville Partnership | Springerville Unit 3 Lease
Consolidated Variable Interest Entities
Percentage of financial and other support provided	100.00%
Springerville Partnership | Springerville Unit 3 Holding LLC
Consolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%
Springerville Partnership | Reportable Legal Entities
Consolidated Variable Interest Entities
Net electric plant	$ 771,876		776,411
Noncontrolling interest	111,768		111,717
Long-term debt	343,313		380,867
Accrued interest	3,977		$ 11,050
Depreciation and amortization	4,534	4,534
Interest	$ 5,861	$ 6,831
Other Limited Partners | Springerville Partnership
Consolidated Variable Interest Entities
Ownership interest held by noncontrolling interest (as a percent)	49.00%

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LEASES - Leasing Arrangements as Lessee (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2020 USD ($) lease MW	Mar. 31, 2019 USD ($)	Dec. 31, 2019 USD ($)
Lease expenses
Operating lease expense	$ 900	$ 1,800
Number of financing leases | lease	0
Lessee operating lease assets and liabilities
Operating lease right-of-use assets, gross	$ 9,312
Less: Accumulated amortization	(985)
Net operating lease right-of-use assets	$ 8,327		$ 7,622
Operating lease right-of-use asset, Statement of Financial Position line item	us-gaap:DeferredCostsCurrentAndNoncurrent
Operating lease liabilities - current	$ (6,355)
Operating lease liabilities - current, Statement of Financial Position line item	us-gaap:LiabilitiesCurrent
Operating lease liabilities - noncurrent	$ (1,921)		$ (1,846)
Operating lease liabilities - noncurrent, Statement of Financial Position line item	tris:OtherDeferredCreditsAndOtherLiabilities
Total operating lease liabilities	$ (8,276)
Weighted average remaining lease term (years)	9 years 3 months 18 days
Weighted average discount rate	3.75%
Brush Generating Station
Operating Lease - Lessee
Megawatt usage | MW	70

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INVESTMENTS IN OTHER ASSOCIATIONS (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Investment in other associations
Investment in other associations	$ 162,562	$ 161,945
Impairment during the period	0	0
Basin Electric Power Cooperative
Investment in other associations
Investment in other associations	117,368	117,368
National Rural Utilities Cooperative Finance Corporation - patronage capital
Investment in other associations
Investment in other associations	11,761	11,761
National Rural Utilities Cooperative Finance Corporation - capital term certificates
Investment in other associations
Investment in other associations	15,885	15,953
CoBank, ACB
Investment in other associations
Investment in other associations	11,141	10,201
Western Fuels Association
Investment in other associations
Investment in other associations	2,193	2,409
Other
Investment in other associations
Investment in other associations	$ 4,214	$ 4,253

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OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
OTHER DEFERRED CHARGES.
Preliminary surveys and investigations	$ 22,167	$ 21,261
Advances to operating agents of jointly owned facilities	10,197	3,917
Operating lease right-of-use assets	8,327	7,622
Other	15,431	9,872
Total other deferred charges	$ 56,122	$ 42,672

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating activities
Net margins including noncontrolling interest	$ (3,291)	$ 8,006
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	47,024	38,145
Amortization of intangible asset		1,831
Amortization of NRECA Retirement Security Plan prepayment	1,343	1,343
Amortization of debt issuance costs	602	577
Impairment loss	259,761
Deferred impairment loss	(268,163)
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(693)	(265)
Changes in operating assets and liabilities:
Accounts receivable	14,230	3,510
Coal inventory	1,843	13,442
Materials and supplies	954	(3,360)
Accounts payable and accrued expenses	8,039	1,876
Accrued interest	17,321	16,787
Accrued property taxes	(2,063)	(1,692)
Other	(11,353)	(26)
Net cash provided by operating activities	65,554	80,174
Investing activities
Purchases of plant	(36,171)	(45,128)
Changes in deferred charges	(6,094)	(4,220)
Proceeds from other investments	68	65
Net cash used in investing activities	(42,197)	(49,283)
Financing activities
Changes in Member advances	(6,905)	(4,407)
Payments of long-term debt	(41,994)	(36,264)
Proceeds from issuance of long-term debt	200,000
Debt issuance costs		(13)
Increase (decrease) in short-term borrowings, net	(87,600)	20,063
Retirement of patronage capital	(13,326)	(11,101)
Equity distribution to noncontrolling interest	(1,268)	(1,454)
Other	(195)	(176)
Net cash provided by (used in) financing activities	48,712	(33,352)
Net decrease in cash, cash equivalents and restricted cash and investments	72,069	(2,461)
Cash, cash equivalents and restricted cash and investments – beginning	113,768
Cash, cash equivalents and restricted cash and investments – ending	185,837	125,129
Supplemental cash flow information:
Cash paid for interest	21,222	23,604
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ 1,044	$ (629)

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Consolidated Statements of Financial Position - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Electric plant
In service	$ 6,126,271	$ 6,090,392
Construction work in progress	156,996	164,924
Total electric plant	6,283,267	6,255,316
Less allowances for depreciation and amortization	(2,928,176)	(2,641,470)
Net electric plant	3,355,091	3,613,846
Other plant	412,291	409,051
Less allowances for depreciation, amortization and depletion	(122,495)	(113,607)
Net other plant	289,796	295,444
Total property, plant and equipment	3,644,887	3,909,290
Other assets and investments
Investments in other associations	162,562	161,945
Investments in and advances to coal mines	19,689	19,681
Restricted cash and investments	4,967	30,516
Other noncurrent assets	8,512	8,654
Total other assets and investments	195,730	220,796
Current assets
Cash and cash equivalents	180,682	83,070
Restricted cash and investments	188	182
Deposits and advances	35,856	28,434
Accounts receivable—Members	97,901	105,371
Other accounts receivable	21,212	28,039
Coal inventory	48,348	50,191
Materials and supplies	92,677	93,632
Total current assets	476,864	388,919
Deferred charges
Regulatory assets	732,784	497,279
Prepayment—NRECA Retirement Security Plan	25,519	26,862
Other	56,122	42,672
Total deferred charges	814,425	566,813
Total assets	5,131,906	5,085,818
Capitalization
Patronage capital equity	1,026,453	1,031,063
Accumulated other comprehensive income (loss)	(7,958)	(1,518)
Noncontrolling interest	111,768	111,717
Total equity	1,130,263	1,141,262
Long-term debt	3,217,571	3,063,351
Total capitalization	4,347,834	4,204,613
Current liabilities
Member advances	11,120	18,025
Accounts payable	100,153	99,033
Short-term borrowings	164,723	252,323
Accrued expenses	35,855	43,761
Current asset retirement obligations	1,802	2,460
Accrued interest	47,037	29,716
Accrued property taxes	27,066	29,129
Current maturities of long-term debt	85,636	81,555
Total current liabilities	473,392	556,002
Deferred credits and other liabilities
Regulatory liabilities	122,051	122,169
Deferred income tax liability	33,969	58,937
Asset retirement and environmental reclamation obligations	81,078	76,454
Other	54,395	56,399
Total deferred credits and other liabilities	291,493	313,959
Accumulated postretirement benefit and postemployment obligations	19,187	11,244
Total equity and liabilities	$ 5,131,906	$ 5,085,818

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Deferred credits and other liabilities
Transmission easements	$ 20,235	$ 20,549
Operating lease liabilities - noncurrent	1,921	1,846
Contract liabilities (unearned revenue) - noncurrent	4,123	4,217
Customer deposits	2,251	3,015
Financial liabilities - reclamation	12,070	12,091
Other	13,795	14,681
Total other deferred credits and other liabilities	54,395	56,399
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way	31,200
Other Deferred Credits and Other Liabilities | Transmission Right of Way Easements
Deferred credits and other liabilities
Transmission easements	$ 20,200	$ 20,500

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SHORT-TERM BORROWINGS (Tables)

3 Months Ended

Mar. 31, 2020

SHORT-TERM BORROWINGS

Schedule of commercial paper

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

	March 31,			December 31,
	2020			2019
Commercial paper outstanding, net of discounts	$	164,723		$	252,323
Weighted average interest rate		1.83	%		1.88	%

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REVENUE (Tables)

3 Months Ended

Mar. 31, 2020

REVENUE

Schedule of revenue from contracts with non-member customers and other operating revenue

The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands):

	Three Months Ended March 31,
	2020		2019
Non-member electric sales:
Long-term contracts	$	12,144	$	11,682
Short-term contracts		3,669		15,048
Other		10,890		14,256
Total non-member electric sales and other operating revenue	$	26,703	$	40,986

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LONG-TERM DEBT

3 Months Ended

Mar. 31, 2020

LONG-TERM DEBT.

LONG-TERM DEBT

NOTE 8 – LONG-TERM DEBT

We have $3.3 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 $25.3 million as of March 31, 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 long-term debt 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, 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 March 31, 2020, we have borrowed $200 million in LIBOR rate loans which are secured under the Revolving Credit Agreement, and issued $165 million in commercial paper against the commercial paper back-up sublimit. As of March 31, 2020, we had $285.0 million in availability under the Revolving Credit Agreement.

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

	March 31,		December 31,
	2020		2019
Total debt	$	3,324,478		3,166,472
Less debt issuance costs		(26,810)		(27,412)
Less debt discounts		(9,846)		(9,906)
Plus debt premiums		15,385		15,752
Total debt adjusted for debt issuance costs, discounts and premiums		3,303,207		3,144,906
Less current maturities		(85,636)		(81,555)
Long-term debt	$	3,217,571	$	3,063,351

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INVESTMENTS IN AND ADVANCES TO COAL MINES

3 Months Ended

Mar. 31, 2020

INVESTMENTS IN AND ADVANCES TO COAL MINES

INVESTMENTS IN AND ADVANCES TO COAL MINES

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):

	March 31,		December 31,
	2020		2019
Investment in Trapper Mine	$	16,014	$	15,881
Advances to Dry Fork Mine		3,675		3,800
Investments in and advances to coal mines	$	19,689	$	19,681

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EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2020

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

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 March 31, 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):

	March 31,
	2020
Postretirement medical benefit obligation at beginning of period	$	10,195
Service cost		141
Interest cost		88
Benefit payments (net of contributions by participants)		(155)
Postretirement medical benefit obligation at end of period	$	10,269
Postemployment medical benefit obligation at end of period		375
Total postretirement and postemployment medical obligations at end of period	$	10,644

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):

	2020
Amounts included in accumulated other comprehensive income at beginning of period	$	(1,387)
Amortization of actuarial (gain) loss into income		11
Amortization of prior service credit into other income		(20)
Amounts included in accumulated other comprehensive income at end of period	$	(1,396)

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):

	March 31,
	2020
Executive benefit restoration obligation at beginning of period	$	674
Service cost		206
Interest cost		291
Plan amendments - prior service cost		5,218
Actuarial loss		2,155
Executive benefit restoration at end of period	$	8,544

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.

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):

	March 31,
	2020
Amounts included in accumulated other comprehensive income at beginning of period	$	(130)
Plan amendments - prior service cost		(5,218)
Amortization of prior service cost into other income		942
Unrecognized actuarial loss		(2,155)
Amounts included in accumulated other comprehensive income at end of period	$	(6,561)