UNITEDSTATES
SECURITIESANDEXCHANGECOMMISSION
WASHINGTON,D.C.20549
FORM10-Q
March 31, 2021 Colorado Westminster, Colorado (Address of principal executive offices) (Zip Code)⌧☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 September 30, 2020◻☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Colorado84-046418984-0464189 Employer IdentificationNo.)employer identification Colorado80234
Title of each class Trading Symbol(s) Name of each exchange on which registered None None None◻☐No ◻(Note:x (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)).⌧☒No◻◻oAcceleratedfiler◻ofiler⌧FilerxSmallerreportingcompany◻☐Emerging growth company◻◻⌧
Page Number GLOSSARY September 30, 2020 December 31, 2019 ASSETS (unaudited) Property, plant and equipment Electric plant In service $ 6,184,657 $ 6,090,392 Construction work in progress 130,651 164,924 Total electric plant 6,315,308 6,255,316 Less allowances for depreciation and amortization (2,975,735) (2,641,470) Net electric plant 3,339,573 3,613,846 Other plant 415,015 409,051 Less allowances for depreciation, amortization and depletion (133,587) (113,607) Net other plant 281,428 295,444 Total property, plant and equipment 3,621,001 3,909,290 Other assets and investments Investments in other associations 159,187 161,945 Investments in and advances to coal mines 19,558 19,681 Restricted cash and investments 4,887 30,516 Other noncurrent assets 8,825 8,654 Total other assets and investments 192,457 220,796 Current assets Cash and cash equivalents 164,965 83,070 Restricted cash and investments 199 182 Deposits and advances 31,586 28,434 Accounts receivable—Utility Members 99,420 105,371 Other accounts receivable 25,198 28,039 Coal inventory 55,879 50,191 Materials and supplies 93,342 93,632 Total current assets 470,589 388,919 Deferred charges Regulatory assets 717,177 497,279 Prepayment—NRECA Retirement Security Plan 22,833 26,862 Other 58,670 42,672 Total deferred charges 798,680 566,813 Total assets $ 5,082,727 $ 5,085,818 EQUITY AND LIABILITIES Capitalization Patronage capital equity $ 1,029,050 $ 1,031,063 Accumulated other comprehensive loss (7,604) (1,518) Noncontrolling interest 113,425 111,717 Total equity 1,134,871 1,141,262 Long-term debt 3,205,904 3,063,351 Total capitalization 4,340,775 4,204,613 Current liabilities Utility Member advances 16,504 18,025 Accounts payable 105,786 99,033 Short-term borrowings — 252,323 Accrued expenses 29,165 43,761 Current asset retirement obligations 2,840 2,460 Accrued interest 45,830 29,716 Accrued property taxes 28,086 29,129 Current maturities of long-term debt 87,178 81,555 Total current liabilities 315,389 556,002 Deferred credits and other liabilities Regulatory liabilities 237,187 122,169 Deferred income tax liability 33,744 58,937 Asset retirement and environmental reclamation obligations 80,303 76,454 Other 56,477 56,399 Total deferred credits and other liabilities 407,711 313,959 Accumulated postretirement benefit and postemployment obligations 18,852 11,244 Total equity and liabilities $ 5,082,727 $ 5,085,818 Tri-State Generation and Transmission Association, Inc. Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Operating revenues Utility Member electric sales $ 346,769 $ 358,586 $ 926,529 $ 942,175 Non-member electric sales 38,606 28,339 71,044 71,843 Other 16,226 12,128 37,150 39,540 401,601 399,053 1,034,723 1,053,558 Operating expenses Purchased power 103,136 103,525 260,804 252,948 Fuel 65,061 67,374 165,679 204,271 Production 39,698 48,619 122,595 148,457 Transmission 43,989 42,305 127,175 122,329 General and administrative 17,081 12,978 49,337 35,887 Depreciation, amortization and depletion 45,775 40,590 137,110 116,879 Coal mining 4,200 1,675 8,021 7,824 Other 2,691 4,640 13,429 12,154 321,631 321,706 884,150 900,749 Operating margins 79,970 77,347 150,573 152,809 Other income Interest 959 1,364 3,248 4,156 Capital credits from cooperatives 1,186 1,186 4,674 4,520 Other income (expense) 197 14,314 348 16,226 2,342 16,864 8,270 24,902 Interest expense Interest 37,673 39,991 114,533 120,754 Interest charged during construction (1,460) (1,961) (5,022) (6,800) 36,213 38,030 109,511 113,954 Income tax benefit (154) (77) (484) (231) Net margins including noncontrolling interest 46,253 56,258 49,816 63,988 Net margin attributable to noncontrolling interest (1,424) (1,113) (4,164) (3,239) Net margins attributable to the Association $ 44,829 $ 55,145 $ 45,652 $ 60,749 Tri-State Generation and Transmission Association, Inc. Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Net margins including noncontrolling interest $ 46,253 $ 56,258 $ 49,816 $ 63,988 Other comprehensive loss: Amortization of actuarial loss on postretirement benefit obligation included in net margin 177 (10) 1,287 13 Unrecognized prior service cost — — (7,373) (214) Other comprehensive loss 177 (10) (6,086) (201) Comprehensive income including noncontrolling interest 46,430 56,248 43,730 63,787 Net comprehensive income attributable to noncontrolling interest (1,424) (1,113) (4,164) (3,239) Comprehensive income attributable to the Association $ 45,006 $ 55,135 $ 39,566 $ 60,548 Tri-State Generation and Transmission Association, Inc. Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Patronage capital equity at beginning of period $ 984,221 $ 1,021,358 $ 1,031,063 $ 1,015,754 Net margins attributable to the Association 44,829 55,145 45,652 60,749 Retirement of patronage capital — — (47,665) — Patronage capital equity at end of period 1,029,050 1,076,503 1,029,050 1,076,503 Accumulated other comprehensive income (loss) at beginning of period (7,781) 184 (1,518) 375 Amortization of prior service cost 177 (10) 1,287 13 Unrecognized prior service cost — — (7,373) (214) Accumulated other comprehensive income (loss) at end of period (7,604) 174 (7,604) 174 Noncontrolling interest at beginning of period 113,189 110,841 111,717 110,169 Net comprehensive income attributable to noncontrolling interest 1,424 1,113 4,164 3,239 Equity distribution to noncontrolling interest (1,188) (1,352) (2,456) (2,806) Noncontrolling interest at end of period 113,425 110,602 113,425 110,602 Total equity at end of period $ 1,134,871 $ 1,187,279 $ 1,134,871 $ 1,187,279 Tri-State Generation and Transmission Association, Inc. Nine Months Ended September 30, 2020 2019 Operating activities Net margins including noncontrolling interest $ 49,816 $ 63,988 Adjustments to reconcile net margins to net cash provided by operating activities: Depreciation, amortization and depletion 137,110 116,879 Amortization of intangible asset — 3,662 Amortization of NRECA Retirement Security Plan prepayment 4,029 4,029 Amortization of debt issuance costs 1,832 1,773 Impairment loss 259,761 37,067 Deferred impairment loss and other closure costs (268,163) (37,067) Deferred membership withdrawal income 110,165 — Capital credit allocations from cooperatives and income from coal mines over refund distributions 2,813 (486) Changes in operating assets and liabilities: Accounts receivable 5,844 (155) Coal inventory (5,688) 3,922 Materials and supplies 290 (2,943) Accounts payable and accrued expenses 9,337 3,418 Accrued interest 16,113 15,691 Accrued property taxes (1,043) (282) Other (16,323) (7,581) Net cash provided by operating activities 305,893 201,915 Investing activities Purchases of plant (100,821) (149,396) Sale of electric plant 26,000 — Changes in deferred charges (4,532) (6,277) Proceeds from other investments 68 65 Net cash used in investing activities (79,285) (155,608) Financing activities Changes in Utility Member advances (1,520) (5,351) Payments of long-term debt (277,119) (91,884) Proceeds from issuance of long-term debt 425,000 34,910 Debt issuance costs (637) (13) Increase (decrease) in short-term borrowings, net (252,323) 23,036 Retirement of patronage capital (60,991) (11,101) Equity distribution to noncontrolling interest (2,456) (2,806) Other (279) (257) Net cash used in financing activities (170,325) (53,466) Net increase (decrease) in cash, cash equivalents and restricted cash and investments 56,283 (7,159) Cash, cash equivalents and restricted cash and investments – beginning 113,768 127,590 Cash, cash equivalents and restricted cash and investments – ending $ 170,051 $ 120,431 Supplemental cash flow information: Cash paid for interest $ 97,218 $ 103,782 Cash paid for income taxes $ — $ — Supplemental disclosure of noncash investing and financing activities: Change in plant expenditures included in accounts payable $ 2,217 $ (873) Tri-State Generation and Transmission Association, Inc. On April 30, 2021, we filed a proposed settlement agreement with FERC related to our stated rate to our Class A members. See Note 17 – Legal. Our share in each jointly owned facility is as follows as of Electric Construction Tri-State Plant in Accumulated Work In Share Service Depreciation Progress Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 395,099 $ 249,804 $ 334 MBPP - Laramie River Station 27.13 % 489,147 301,561 5,075 Total $ 884,246 $ 551,365 $ 5,409 September 30, December 31, 2020 2019 Regulatory assets Deferred income tax expense (1) $ 33,744 $ 58,937 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 81,996 83,714 Goodwill – J.M. Shafer (3) 47,008 49,145 Goodwill – Colowyo Coal (4) 36,419 37,194 Deferred debt prepayment transaction costs (5) 134,459 140,931 Deferred Holcomb expansion impairment loss (6) 89,988 93,494 Unrecovered plant (7) 293,563 33,864 Total regulatory assets 717,177 497,279 Regulatory liabilities Interest rate swap - realized gain (8) 3,391 3,744 Deferred revenues (9) 75,853 75,853 Membership withdrawal (10) 157,943 42,572 Total regulatory liabilities 237,187 122,169 Net regulatory asset $ 479,990 $ 375,110 Investments in other associations are as follows (dollars in thousands): September 30, December 31, 2020 2019 Basin Electric Power Cooperative $ 114,036 $ 117,368 National Rural Utilities Cooperative Finance Corporation - patronage capital 11,933 11,761 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,885 15,953 CoBank, ACB 11,141 10,201 Western Fuels Association, Inc. 2,302 2,409 Other 3,890 4,253 Investments in other associations $ 159,187 $ 161,945 September 30, December 31, 2020 2019 Investment in Trapper Mine $ 16,279 $ 15,881 Advances to Dry Fork Mine 3,279 3,800 Investments in and advances to coal mines $ 19,558 $ 19,681 The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands): September 30, December 31, 2020 2019 Cash and cash equivalents $ 164,965 $ 83,070 Restricted cash and investments - current 199 182 Restricted cash and investments - noncurrent 4,887 30,516 Cash, cash equivalents and restricted cash and investments $ 170,051 $ 113,768 September 30, December 31, 2020 2019 Accounts receivable - Utility Members $ 99,420 $ 105,371 Other accounts receivable - trade: Non-member electric sales 7,900 4,727 Other 16,615 20,628 Total other accounts receivable - trade 24,515 25,355 Other accounts receivable - nontrade 683 2,684 Total other accounts receivable $ 25,198 $ 28,039 Contract liabilities (unearned revenue) $ 6,281 $ 7,041 September 30, December 31, 2020 2019 Preliminary surveys and investigations $ 23,012 $ 21,261 Advances to operating agents of jointly owned facilities 8,686 3,917 Operating lease right-of-use assets 10,086 7,622 Other 16,886 9,872 Total other deferred charges $ 58,670 $ 42,672 Long-term debt consists of the following (dollars in thousands): September 30, December 31, 2020 2019 Total debt $ 3,314,353 3,166,472 Less debt issuance costs (26,218) (27,412) Less debt discounts (9,722) (9,906) Plus debt premiums 14,669 15,752 Total debt adjusted for debt issuance costs, discounts and premiums 3,293,082 3,144,906 Less current maturities (87,178) (81,555) Long-term debt $ 3,205,904 $ 3,063,351 September 30, December 31, 2020 2019 Commercial paper outstanding, net of discounts $ — $ 252,323 Weighted average interest rate — % 1.88 % At Mine is currently in post-reclamation monitoring. Nine Months Ended September 30, 2020 Obligations at beginning of period $ 78,914 Liabilities incurred — Liabilities settled (824) Accretion expense 1,895 Change in cash flow estimate 3,158 Total obligations at end of period $ 83,143 Less current obligations at end of period (2,840) Long-term obligations at end of period $ 80,303 September 30, December 31, 2020 2019 Transmission easements $ 20,148 $ 20,549 Operating lease liabilities - noncurrent 1,705 1,846 Contract liabilities (unearned revenue) - noncurrent 3,781 4,217 Customer deposits 7,404 3,015 Financial liabilities - reclamation 10,217 12,091 Other 13,222 14,681 Total other deferred credits and other liabilities $ 56,477 $ 56,399 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. As of June 30, 2021, the plans will cease to provide postretirement medical benefits for employees who retire after June 30, 2021. Nine Months Ended September 30, 2020 Postretirement medical benefit obligation at beginning of period $ 10,195 Service cost 422 Interest cost 264 Benefit payments (net of contributions by participants) (465) Postretirement medical benefit obligation at end of period $ 10,416 Postemployment medical benefit obligation at end of period 375 Total postretirement and postemployment medical obligations at end of period $ 10,791 The 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): Accumulated other comprehensive loss at beginning of period Amortization of prior service credit into other income Accumulated other comprehensive loss at end of period As of April 30, 2021, the plans will cease to add new participants and no new executives will be eligible for the plan. Nine Months Ended September 30, 2020 Executive benefit restoration obligation at beginning of period $ 674 Service cost 312 Interest cost 417 Plan amendments - prior service cost 5,218 Benefit payments (715) Actuarial loss 2,155 Executive benefit restoration at end of period $ 8,061 In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. 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): Accumulated other comprehensive loss at beginning of period Amortization of prior service cost into other income Amortization of actuarial loss Accumulated other comprehensive loss at end of period In addition to our Utility Member electric sales, we have non-member electric sales and other operating revenue which consist of several revenue streams. The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Non-member electric sales: Long-term contracts $ 9,423 $ 12,647 $ 32,817 $ 35,241 Short-term contracts 29,183 15,692 38,227 36,602 Other 16,226 12,128 37,150 39,540 Total non-member electric sales and other operating revenue $ 54,832 $ 40,467 $ 108,194 $ 111,383 assets. Rent expense for all short-term and long-term operating leases was Our consolidated statements of financial position include the following lease components (dollars in thousands): September 30, December 31, 2020 2019 Operating leases Operating lease right-of-use assets $ 11,464 $ 8,376 Less: Accumulated amortization (1,378) (754) Net operating lease right-of-use assets $ 10,086 $ 7,622 Operating lease liabilities - current $ (556) $ (5,533) Operating lease liabilities - noncurrent (1,705) (1,846) Total operating lease liabilities $ (2,261) $ (7,379) Operating leases Weighted average remaining lease term (years) 7.46 9.5 Weighted average discount rate 3.83% 3.80% Year 1 $ 609 Year 2 444 Year 3 341 Year 4 315 Year 5 196 Thereafter 737 Total lease payments $ 2,642 Less imputed interest (381) Total $ 2,261 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: September 30, 2020 December 31, 2019 Estimated Estimated Cost Fair Value Cost Fair Value Marketable securities $ 477 $ 429 $ 715 $ 654 2020. September 30, 2020 December 31, 2019 Principal Estimated Principal Estimated Amount Fair Value Amount Fair Value Total debt $ 3,314,353 $ 3,926,312 $ 3,166,472 $ 3,608,341 September 30, December 31, 2020 2019 Net electric plant $ 762,808 $ 776,411 Noncontrolling interest 113,425 111,717 Long-term debt 342,680 380,867 Accrued interest 3,977 11,050 September 30, September 30, 2020 2019 2020 2019 Depreciation, amortization and depletion $ 4,535 $ 4,535 $ 13,603 $ 13,603 Interest 5,646 6,281 $ 17,157 19,045 FERC Tariff and Declaratory Order: issues, including the complaints filed by United Power, Inc. ("United Power") and La Plata Electric Association ("LPEA") with the COPUC. United Power and LPEA. FERC, United Power, and the other parties reached agreement on the procedures and schedule for the Jurisdictional PDO and abeyance on all non-Jurisdictional PDO matters and such filing was made to the D.C. Circuit Court of Appeals. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 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. Our wholesale electric service contracts with our 42 Utility Members extend through 2050. Each Utility Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled by the Utility Member. As of year ended December 31, 2020. calculation is time-intensive and complex and that we are working on a contract termination procedure to be filed with FERC. In comments against such Board policy. allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void further information. Utility Members through contract flexibility. In connection with such early retirements, our Board continues to evaluate the creation of additional 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. 2020. As of December 31, 2020, our DSR was 1.19 and our ECR was 24.7 percent. Pursuant to our Master Indenture, DSR and ECR are calculated based on unconsolidated Tri-State financials and calculated in accordance with the system of accounts proscribed by FERC, not GAAP. Members. Unaudited Consolidated Financial Statements in Item 1 for further information. Revenues from electric power sales to our Utility Members are primarily from our Class A wholesale rate schedule filed with FERC. In •the expansion or contraction of operations among our Utility Members’ commercial and industrial customers; March 31, 2020 Three Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating revenues Utility Member electric sales $ 346,769 $ 358,586 $ (11,817) (3.3)% Non-member electric sales 38,606 28,339 10,267 36.2% Other 16,226 12,128 4,098 33.8% Total operating revenues $ 401,601 $ 399,053 $ 2,548 0.6% Energy sales (in MWh): Utility Member electric sales 4,512,087 4,625,494 (113,407) (2.5)% Non-member electric sales 533,360 549,427 (16,067) (2.9)% 5,045,447 5,174,921 (129,474) (2.5)% The following is a summary of the components of our operating expenses for the three months ended Three Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating expenses Purchased power $ 103,136 $ 103,525 $ (389) (0.4)% Fuel 65,061 67,374 (2,313) (3.4)% Production 39,698 48,619 (8,921) (18.3)% Transmission 43,989 42,305 1,684 4.0% General and administrative 17,081 12,978 4,103 31.6% Depreciation, amortization and depletion 45,775 40,590 5,185 12.8% Coal mining 4,200 1,675 2,525 150.7% Other 2,691 4,640 (1,949) (42.0)% Total operating expenses $ 321,631 $ 321,706 $ (75) (0.0)% Nine Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating revenues Member electric sales $ 926,529 $ 942,175 $ (15,646) (1.7)% Non-member electric sales 71,044 71,843 (799) (1.1)% Other 37,150 39,540 (2,390) (6.0)% Total operating revenues $ 1,034,723 $ 1,053,558 $ (18,835) (1.8)% Energy sales (in MWh): Member electric sales 12,246,955 12,393,692 (146,737) (1.2)% Non-member electric sales 1,177,370 1,444,087 (266,717) (18.5)% 13,424,325 13,837,779 (413,454) (3.0)% Nine Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating expenses Purchased power $ 260,804 $ 252,948 $ 7,856 3.1% Fuel 165,679 204,271 (38,592) (18.9)% Production 122,595 148,457 (25,862) (17.4)% Transmission 127,175 122,329 4,846 4.0% General and administrative 49,337 35,887 13,450 37.5% Depreciation, amortization and depletion 137,110 116,879 20,231 17.3% Coal mining 8,021 7,824 197 2.5% Other 13,429 12,154 1,275 10.5% Total operating expenses $ 884,150 $ 900,749 $ (16,599) (1.8)% Financial condition as of 2020 million was primarily due to debt payments of $46.1 million (principally $41.0 million for the Springerville certificates). In April 2021, we paid off the remaining $22.0 million balance of the First Mortgage Obligations, Series 2009C. Available Authorized September 30, Amount 2020 Revolving Credit Agreement $ 650,000 (1) $ 650,000 March 31, 2021. 31, 2021. Cash Flow March 31, 2020 licenses. upgrades. These decreases were partially offset by a decrease in short-term borrowings of $87.6 million. 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. system. complex and change frequently. For a discussion regarding potential effects on our business from environmental regulations, see also “Item 1 – BUSINESS – ENVIRONMENTAL REGULATION” and 2020. 32.1 32.2 95 101 XBRL Interactive Data File. Tri-State Generation and Transmission Date: By: /s/ Duane Highley Duane Highley Chief Executive Officer Date: /s/ Patrick L. Bridges Patrick L. Bridges Senior Vice President/Chief Financial Officer (Principal Financial Officer)no0 authorized or outstanding equity securities.SEPTEMBER 30, 2020253838384040Abbreviations or Acronyms Definition Basin Basin Electric Power Cooperative Board Board of Directors CDPHE Colorado Department of Public Health and Environment CFC National Rural Utilities Cooperative Finance Corporation CoBank CoBank, ACB Colowyo Coal Colowyo Coal Company L.P., a subsidiary of ours COPUC Colorado Public Utilities Commission COVID-19 coronavirus disease 2019 that was declared a pandemic by the World Health Organization in March 2020 D.C. Circuit Court of Appeals United States Court of Appeals for the District of Columbia Circuit DSR Debt Service Ratio (as defined in our Master Indenture) ECR Equity to Capitalization Ratio (as defined in our Master Indenture) DMEA Delta-Montrose Electric Association FERC Federal Energy Regulatory Commission Fitch Fitch Ratings Inc. FPA Federal Power Act, as amended GAAP accounting principles generally accepted in the United States Jurisdictional PDO our Petition for Declaratory Order on Jurisdiction under Part II of Federal Power Act, filed with FERC on December 23, 2019, EL20-16-000 kWh kilowatt hour LIBOR London Interbank Offered Rate LPEA La Plata Electric Association, Inc. Master Indenture Master First Mortgage Indenture, Deed of Trust and Security Agreement, dated effective as of December 15, 1999, between us and Wells Fargo Bank, National Association, as trustee MBPP Missouri Basin Power Project Members our Utility Members and Non-Utility Members Moody’s Moody’s Investors Services, Inc. MW megawatt MWh megawatt hour Non-Utility Members our non-utility members Revolving Credit Agreement Credit Agreement, dated as of April 25, 2018, between us and CFC, as administrative agent S&P Standard & Poor’s Global Ratings SEC Securities and Exchange Commission Springerville Partnership Springerville Unit 3 Partnership LP, a subsidiary of ours Springerville Unit 3 Springerville Generating Station Unit 3 Tri-State, We, Our, Us, the Association Tri-State Generation and Transmission Association, Inc. United Power United Power, Inc. Utility Members our electric distribution member systems, consisting of both Class A members and Class B members “forward-looking“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.iiMarch 31, 2021 December 31, 2020 ASSETS (unaudited) Property, plant and equipment Electric plant In service $ 6,338,525 $ 6,254,652 Construction work in progress 85,386 89,447 Total electric plant 6,423,911 6,344,099 Less allowances for depreciation and amortization (3,073,651) (2,991,393) Net electric plant 3,350,260 3,352,706 Other plant 457,837 456,924 Less allowances for depreciation, amortization and depletion (145,304) (133,012) Net other plant 312,533 323,912 Total property, plant and equipment 3,662,793 3,676,618 Other assets and investments Investments in other associations 164,248 162,975 Investments in and advances to coal mines 2,614 2,799 Restricted cash and investments 4,546 4,682 Other noncurrent assets 15,390 14,889 Total other assets and investments 186,798 185,345 Current assets Cash and cash equivalents 109,483 127,187 Restricted cash and investments 274 205 Deposits and advances 37,604 32,012 Accounts receivable—Utility Members 88,369 96,637 Other accounts receivable 16,286 20,570 Electric plant held for sale Electric plant held for sale 0 4,877 Coal inventory 53,211 55,762 Materials and supplies 81,567 82,119 Total current assets 386,794 419,369 Deferred charges Regulatory assets 699,480 710,268 Prepayment—NRECA Retirement Security Plan 20,146 21,490 Other 46,638 33,646 Total deferred charges 766,264 765,404 Total assets $ 5,002,649 $ 5,046,736 EQUITY AND LIABILITIES Capitalization Patronage capital equity $ 969,029 $ 978,519 Accumulated other comprehensive loss (6,357) (5,714) Noncontrolling interest 113,807 114,851 Total equity 1,076,479 1,087,656 Long-term debt 3,147,423 3,200,181 Total capitalization 4,223,902 4,287,837 Current liabilities Utility Member advances 18,128 16,592 Accounts payable 107,590 98,654 Accrued expenses 31,583 40,736 Current asset retirement obligations 11,080 11,044 Accrued interest 45,321 27,520 Accrued property taxes 27,503 32,794 Current maturities of long-term debt 94,592 87,587 Total current liabilities 335,797 314,927 Deferred credits and other liabilities Regulatory liabilities 203,981 224,953 Deferred income tax liability 19,702 19,591 Asset retirement and environmental reclamation obligations 127,705 127,045 Other 72,401 54,600 Total deferred credits and other liabilities 423,789 426,189 Accumulated postretirement benefit and postemployment obligations 19,161 17,783 Total equity and liabilities $ 5,002,649 $ 5,046,736 Three Months Ended March 31, 2021 2020 Operating revenues Utility Member electric sales $ 272,798 $ 292,763 Non-member electric sales 38,174 15,813 Other 15,000 10,890 325,972 319,466 Operating expenses Purchased power 87,017 71,015 Fuel 60,547 61,069 Production 40,901 43,188 Transmission 44,671 41,540 General and administrative 14,587 16,215 Depreciation, amortization and depletion 52,755 47,024 Coal mining 1,541 2,734 Other 2,551 7,683 304,570 290,468 Operating margins 21,402 28,998 Other income Interest 877 1,305 Capital credits from cooperatives 4,273 3,353 Other income (expense) 857 (250) 6,007 4,408 Interest expense Interest 36,115 38,867 Interest charged during construction (974) (1,961) 35,141 36,906 Income tax expense (benefit) Income tax expense (benefit) 109 (209) Net margins including noncontrolling interest (7,841) (3,291) Net margin attributable to noncontrolling interest (1,649) (1,319) Net margins attributable to the Association $ (9,490) $ (4,610) Three Months Ended March 31, 2021 2020 Net margins including noncontrolling interest $ (7,841) $ (3,291) Other comprehensive loss: Unrealized loss on securities available for sale (34) 0 Amortization of actuarial loss on postretirement benefit obligation included in net margin 512 933 Unrecognized prior service cost (1,121) (7,373) Other comprehensive loss (643) (6,440) Comprehensive loss including noncontrolling interest (8,484) (9,731) Net comprehensive income attributable to noncontrolling interest (1,649) (1,319) Comprehensive loss attributable to the Association $ (10,133) $ (11,050) Three Months Ended March 31, 2021 2020 Patronage capital equity at beginning of period $ 978,519 $ 1,031,063 Net margins attributable to the Association (9,490) (4,610) Patronage capital equity at end of period 969,029 1,026,453 Accumulated other comprehensive loss at beginning of period (5,714) (1,518) Unrealized loss on securities available for sale (34) 0 Amortization of prior service cost 512 933 Unrecognized prior service cost (1,121) (7,373) Accumulated other comprehensive loss at end of period (6,357) (7,958) Noncontrolling interest at beginning of period 114,851 111,717 Net comprehensive income attributable to noncontrolling interest 1,649 1,319 Equity distribution to noncontrolling interest (2,693) (1,268) Noncontrolling interest at end of period 113,807 111,768 Total equity at end of period $ 1,076,479 $ 1,130,263 Three Months Ended March 31, 2021 2020 Operating activities Net margins including noncontrolling interest $ (7,841) $ (3,291) Adjustments to reconcile net margins to net cash provided by operating activities: Depreciation, amortization and depletion 52,755 47,024 Amortization of NRECA Retirement Security Plan prepayment 1,343 1,343 Amortization of debt issuance costs 627 602 Impairment loss 0 259,761 Deferred impairment loss and other closure costs 0 (268,163) Recognition of deferred revenue Recognition of deferred revenue (20,834) 0 Deposits associated with generator interconnection requests Deposits associated with generator interconnection requests 17,130 0 Capital credit allocations from cooperatives and income from coal mines over refund distributions (1,159) (693) Changes in operating assets and liabilities: Accounts receivable 10,224 14,230 Coal inventory 2,550 1,843 Materials and supplies 552 954 Accounts payable and accrued expenses 15,585 8,039 Accrued interest 17,800 17,321 Accrued property taxes (5,291) (2,063) Other (7,430) (11,353) Net cash provided by operating activities 76,011 65,554 Investing activities Purchases of plant (22,775) (36,171) Changes in deferred charges (9,786) (6,094) Proceeds from other investments 72 68 Net cash used in investing activities (32,489) (42,197) Financing activities Changes in Member advances Changes in Member advances 1,536 (6,905) Payments of long-term debt (46,109) (41,994) Proceeds from issuance of long-term debt 0 200,000 Decrease in short-term borrowings, net Decrease in short-term borrowings, net 0 (87,600) Retirement of patronage capital (13,705) (13,326) Equity distribution to noncontrolling interest (2,693) (1,268) Other (322) (195) Net cash provided by (used in) financing activities Net cash provided by (used in) financing activities (61,293) 48,712 Net increase (decrease) in cash, cash equivalents and restricted cash and investments (17,771) 72,069 Cash, cash equivalents and restricted cash and investments – beginning 132,074 113,768 Cash, cash equivalents and restricted cash and investments – ending $ 114,303 $ 185,837 Supplemental cash flow information: Cash paid for interest $ 18,074 $ 21,222 Cash paid for income taxes $ 0 $ 0 Supplemental disclosure of noncash investing and financing activities: Change in plant expenditures included in accounts payable $ (616) $ 1,044 and Nine Months Ended September 30,March 31, 2021 and 2020 and 201920192020 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of September 30, 2020,March 31, 2021, results of operations for the three and nine months ended September 30,March 31, 2021 and 2020, and 2019, and cash flows for the ninethree months ended September 30,March 31, 2021 and 2020 and 2019 are not necessarily indicative of the results that may be expected for an entire year or any other period.three3 classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. We have forty-twoNaN electric distribution member systems who are Class A members (“Class A Member(s)”) to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no0 Class B members. We have three3 non-utility members (“Non-Utility Members”). Our Class A Membersmembers and any Class B members are collectively referred to as our “Utility Members.” Our Class A Members,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 Membersmembers was filed at FERC on December 23, 2019 and was accepted by FERC on March 20, 2020.1716 – 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.two2 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.September 30, 2020March 31, 2021 (dollars in thousands):Tri-State
ShareElectric
Plant in
ServiceAccumulated
DepreciationConstruction
Work In
ProgressYampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 395,810 $ 253,638 $ 418 MBPP - Laramie River Station 27.13 % 498,918 317,538 4,051 Total $ 894,728 $ 571,176 $ 4,469 We are subject tooperations. In accordance with these accounting requirements,operations, some revenues and expenses have been deferred at the discretion of our Board of Directors (“Board”), subject to FERC approval, 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.(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.Regulatory assets Deferred income tax expense (1) $ 19,641 $ 19,641 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 80,851 81,424 Goodwill – J.M. Shafer (3) 45,584 46,296 Goodwill – Colowyo Coal (4) 35,903 36,161 Deferred debt prepayment transaction costs (5) 130,145 132,302 Deferred Holcomb expansion impairment loss (6) 87,651 88,819 Unrecovered plant (7) 299,705 305,625 Total regulatory assets 699,480 710,268 Regulatory liabilities Interest rate swap - realized gain (8) and other 3,155 3,293 Deferred revenues (9) 42,883 63,717 Membership withdrawal (10) 157,943 157,943 Total regulatory liabilities 203,981 224,953 Net regulatory asset $ 495,499 $ 485,315 (3)Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates.(4)Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members through rates.(5)Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members through rates.(6)Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. Beginning January 2020, the deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates.(7)Represents deferral of the impairment losses related to the early retirement of the Nucla and Escalante Generating Stations. In July 2019, our Board took action for the early retirement of the Nucla Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement of the Nucla Generating Station, we recognized an impairment loss of $37.1 million during the third quarter of 2019. On September 19, 2019, the Nucla Generating Station was officially retired from service. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. In January 2020, our Board approved the early retirement of the Escalante Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $268.2 million during the first quarter of 2020. The deferred impairment loss for Escalante Generating Station will be amortized to depreciation, amortization and depletion expense beginning in 2021 through the end of 2045, which was the depreciable life of Escalante Generating Station, and is expected to be recovered from our Utility Members through rates. The annual amortization is expected to approximate the former annual Escalante Generating Station depreciation for the remaining life of the asset.(8)Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods.(9)Represents deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members through reduced rates when recognized in non-member electric sales revenue in future periods.
(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.(10)Represents the deferral of the recognition of other income related to the June 30, 2016 withdrawal of a former Utility Member from membership in us and the June 30, 2020 withdrawal of Delta-Montrose Electric Association (“DMEA”) from membership in us. In connection with the DMEA withdrawal, we recognized $110.2 million of other income and $5.2 million of gain on sale of assets which was subsequently deferred. The total deferred membership withdrawal income will be refunded to Utility Members through reduced rates, subject to FERC approval, when recognized in other income in future periods.8Basin Electric Power Cooperative $ 118,295 $ 118,295 National Rural Utilities Cooperative Finance Corporation - patronage capital 11,933 11,933 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,149 15,221 CoBank, ACB 12,707 11,141 Western Fuels Association, Inc. 2,200 2,283 Other 3,964 4,102 Investments in other associations $ 164,248 $ 162,975 no0 impairments of these investments recognized during the ninethree months ended September 30, 2020March 31, 2021 or during 2019.NOTE 4 – INVESTMENTS IN AND ADVANCES TO COAL MINES We have direct ownership and investments in coal mines to support our coal generating resources. We, and certain participants in the Yampa Project, are members of Trapper Mining, which is organized as a cooperative and is the owner and operator of the Trapper Mine near Craig, Colorado. Our investment in Trapper Mining is recorded using the equity method. In addition, we have ownership in Western Fuels Association, Inc. (“WFA”), which is an owner of Western Fuels-Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. Dry Fork Mine provides coal to the Laramie River Generating Station (owned by the participants of MBPP). We, through our undivided interest in the jointly owned facility of MBPP, advance funds to the Dry Fork Mine.Investments in and advances to coal mines are as follows (dollars in thousands):54 – CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS9Cash and cash equivalents $ 109,483 $ 127,187 Restricted cash and investments - current 274 205 Restricted cash and investments - noncurrent 4,546 4,682 Cash, cash equivalents and restricted cash and investments $ 114,303 $ 132,074 Our Board Policy for Financial Goals and Capital Credits was revised in 2018 to provide that our Board will endeavor to fund an internally restricted cash account for the purpose of cash funding deferred revenues and incomes held as regulatory liabilities. In connection with such policy, our Board internally restricted cash in the amount of $25.5 million as of December 31, 2019 which was included in restricted cash and investments - noncurrent. Our Board may, at any time and for any reason, unrestrict any internally restricted cash. On March 10, 2020, our Board took action to unrestrict the $25.5 million balance of the restricted cash in response to volatile market conditions.65 – CONTRACT ASSETS AND CONTRACT LIABILITIES1312 – Revenue.ninethree months ended September 30, 2020,March 31, 2021, we recognized $0.9$0.1 million of this unearned revenue in other operating revenues on our consolidated statements of operations.10Accounts receivable - Utility Members $ 88,369 $ 96,637 Other accounts receivable - trade: Non-member electric sales 3,239 5,231 Other 9,855 9,785 Total other accounts receivable - trade 13,094 15,016 Other accounts receivable - nontrade 3,192 5,554 Total other accounts receivable $ 16,286 $ 20,570 Contract liabilities (unearned revenue) $ 6,301 $ 6,025 76 – OTHER DEFERRED CHARGESPreliminary surveys and investigations $ 12,142 $ 12,886 Advances to operating agents of jointly owned facilities 11,425 2,071 Operating lease right-of-use assets 7,999 7,985 Other 15,072 10,704 Total other deferred charges $ 46,638 $ 33,646 1514 – Leases.87 – LONG-TERM DEBT$3.2$3.1 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement (“Master Indenture”) except for one1 unsecured note in the amount of $21.5$17.7 million as of September 30, 2020.March 31, 2021. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement on an annual basis and an equity to capitalization ratio requirement of at least 18 percent at the end of each fiscal year. Other than the Springerville certificates that has a debt service ratio requirement of at least 1.02 on an annual basis, all other long-term debt contains a debt service ratio requirement of at least 1.10 on an annual basis.September 30, 2020,March 31, 2021, we had $650.0 million in availability under the Revolving Credit Agreement.11Total debt $ 3,262,606 $ 3,308,715 Less debt issuance costs (24,963) (25,590) Less debt discounts (9,595) (9,659) Plus debt premiums 13,967 14,302 Total debt adjusted for debt issuance costs, discounts and premiums 3,242,015 3,287,768 Less current maturities (94,592) (87,587) Long-term debt $ 3,147,423 $ 3,200,181 98 – SHORT-TERM BORROWINGSTheAs of March 31, 2021 and December 31, 2020, we had 0 commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary, but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on our consolidated statements of financial position.Commercial paper consisted of the following (dollars in thousands):September 30, 2020,March 31, 2021, $500.0 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 87 – Long-Term Debt.109 – ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS Mine, and the Fort Union Mine. The New Horizon12OneNaN pit at the Colowyo Mine began final reclamation in 20182019 with the other remaining pits still being actively mined. 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.
March 31, 2021Obligations at beginning of period $ 138,089 Liabilities incurred 0 Liabilities settled (107) Accretion expense 803 Change in cash flow estimate 0 Total obligations at end of period $ 138,785 Less current obligations at end of period (11,080) Long-term obligations at end of period $ 127,705 1110 – OTHER DEFERRED CREDITS AND OTHER LIABILITIESTransmission easements $ 19,621 $ 19,983 Operating lease liabilities - noncurrent 1,761 1,590 Contract liabilities (unearned revenue) - noncurrent 3,611 3,702 Customer deposits 8,935 7,712 Financial liabilities - reclamation 11,924 12,081 Deposits associated with generator interconnection requests Deposits associated with generator interconnection requests 17,130 0 Other 9,419 9,532 Total other deferred credits and other liabilities $ 72,401 $ 54,600 $31.2$29.4 million will be paid by us for these easements from 20202021 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $20.1$19.6 and $20.5$20.0 million as of September 30, 2020March 31, 2021 and December 31, 2019,2020, respectively, which are recorded as other deferred credits and other liabilities.1514 – Leases.131211 – EMPLOYEE BENEFIT PLANSthree3 medical plans for all non-bargaining unit employees under the age of 65. TwoNaN 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 three3 of these non-bargaining unit medical plans offer postemployment medical benefits to employees on long-term disability. The plans were unfunded at September 30, 2020,March 31, 2021, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles.
March 31, 2021Postretirement medical benefit obligation at beginning of period $ 9,985 Service cost 150 Interest cost 65 Benefit payments (net of contributions by participants) (148) Postretirement medical benefit obligation at end of period $ 10,052 Postemployment medical benefit obligation at end of period 419 Total postretirement and postemployment medical obligations at end of period $ 10,471 14
March 31, 2021Nine Months EndedSeptember 30, 2020$(1,387)Amortization of actuarial (gain) loss into income11(59)$(1,435)
March 31, 2021Executive benefit restoration obligation at beginning of period $ 7,379 Service cost 137 Interest cost 53 Actuarial loss 1,121 Executive benefit restoration at end of period $ 8,690 Fair value of plan assets at beginning of period $ 6,955 Employer contributions 403 Actual return on plan assets $ (41) Fair value of plan assets at end of period $ 7,317 Net liability recognized $ 1,373 15
March 31, 2021Nine Months EndedSeptember 30, 2020$(130)Plan amendments - prior service cost(5,218)1,336171 Curtailment and settlement 141 Unrecognized actuarial loss (2,155)$(6,167)1312 – REVENUE We had a contract with DMEA that extended through 2040. DMEA withdrew from membership in us on June 30, 2020 and DMEA’s contract was assigned by us to DMEA’s new third-party power supplier.three3 billing components: an energy rate and two2 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.16Three Months Ended March 31, 2021 2020 Non-member electric sales: Long-term contracts $ 8,706 $ 12,144 Short-term contracts 8,634 3,669 Recognition of deferred revenue Recognition of deferred revenue 20,834 0 Other 15,000 10,890 Total non-member electric sales and other operating revenue $ 53,174 $ 26,703 lease revenues, coal sales and revenue from supplying steam and water.. Other operating revenue also includes revenue we receive from two2 of our Non-Utility Members. Wheeling revenue is earned when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms which is within 20 days of the date the invoice is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Steam and waterWater revenue is derived from supplying steam and water resources 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.1413 – INCOME TAXEStaxes. However,taxes, which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in accordance with our regulatory accounting treatment,the consolidated financial statements. Effective January 1, 2020, we adopted the normalization method of recognizing deferred income taxes pursuant to FERC regulation. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability.liability, as approved by our Board. 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 consolidated17statements of operations includes only the current provision. This liability method is included in our rate filing accepted by FERC on March 20, 2020; however, FERC may require a different method for the recovery of income taxes. Our consolidated statements of operations included an income tax benefitexpense of $0.5$0.1 million for the ninethree months ended September 30, 2020March 31, 2021 and an income tax benefit of $0.2 million for the comparable period in 2019. These income tax benefits are due to an alternative minimum tax credit refund.During the first quarter of 2020, we recorded a $19 million decrease in our deferred tax asset valuation allowance due to the deferred tax treatment of an abandonment loss. No further changes to the valuation allowance were needed for the nine-month period ended September 30, 2020.The Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) was signed into law on March 27, 2020. The CARES Act includes certain corporate income tax provisions which have been evaluated by us. The CARES Act did not have a material impact on our consolidated financial statements.1514 – LEASESassets 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.$1.2$1.0 million for the three months ended September 30, 2020March 31, 2021 and $1.8$0.9 million for the comparable period in 2019. Rent expense for all short-term and long-term operating leases was $2.8 million for the nine months ended September 30, 2020 and $5.4 million for the comparable period in 2019.2020. Rent expense is included in operating expenses on our consolidated statements of operations. As of September 30, 2020,March 31, 2021, there were no0 arrangements accounted for as finance leases.18Operating leases Operating lease right-of-use assets $ 9,331 $ 9,223 Less: Accumulated amortization (1,332) (1,238) Net operating lease right-of-use assets $ 7,999 $ 7,985 Operating lease liabilities - current $ (499) $ (526) Operating lease liabilities - noncurrent (1,761) (1,590) Total operating lease liabilities $ (2,260) $ (2,116) Operating leases Weighted average remaining lease term (years) 7.7 7.6 Weighted average discount rate 3.85 % 3.84 % Year 1 $ 527 Year 2 365 Year 3 336 Year 4 286 Year 5 100 Thereafter 690 Total lease payments $ 2,304 Less imputed interest (44) Total $ 2,260 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.assets. The revenue from these lease agreements of $1.8 million and $1.6 million for the three months ended September 30,March 31, 2021 and 2020, and 2019, respectively, and $5.0 million and $10.5 million for the nine months ended September 30, 2020 and 2019, respectively, are included in other operating revenue on our consolidated statements of operations.17-16- 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.1615 – FAIR VALUE19March 31, 2021 December 31, 2020 Cost Estimated
Fair ValueCost Estimated
Fair ValueEBR Trust investments $ 7,384 $ 7,316 $ 6,955 $ 6,955 March 31, 2021 December 31, 2020 Cost Estimated
Fair ValueCost Estimated
Fair ValueMarketable securities $ 493 $ 503 $ 491 $ 478 $102.2$88.2 million as of September 30, 2020March 31, 2021 and $79.0$94.6 million as of December 31, 2019.20March 31, 2021 December 31, 2020 Principal
AmountEstimated
Fair ValuePrincipal
AmountEstimated
Fair ValueTotal debt $ 3,262,606 $ 3,748,334 $ 3,308,715 $ 3,908,497 1716 – VARIABLE INTEREST ENTITIESNet electric plant $ 753,739 $ 758,273 Noncontrolling interest 113,807 114,852 Long-term debt 301,066 342,355 Accrued interest 3,488 9,942 and nine months ended September 30,March 31, 2021 and 2020 and 2019 (dollars in thousands):March 31, 2021 2020 Depreciation, amortization and depletion $ 4,534 $ 4,534 Interest 5,185 5,861 21Unconsolidated Variable Interest EntitiesWestern 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 received 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 $2.3 million at September 30, 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 September 30, 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 $16.3 million at September 30, 2020 and $15.9 million at December 31, 2019.1817 – LEGALTransmission Agreement: 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 the22current 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 suspended and the parties have reached a resolution of this matter without us incurring any liability. The resolution of this matter is subject to FERC approval. On October 20, 2020, an unexecuted version of an amended and restated transmission agreement to resolve this matter was filed with FERC for approval. It is not possible to predict if FERC will approve this agreement. At Because of increased pressure by states to regulate our July 2019 Board meeting, our Board authorized us to take action to place us under wholesale rate regulationrates and charges with impact in other states setting up untenable conflict, we sought consistent federal jurisdiction by FERC. On September 3,This was accomplished with the addition of non-cooperative members in 2019, a membership agreement withspecifically MIECO, Inc. as a Non-Utility Member MIECO, Inc.,on September 3, 2019. On the same date, we became effective. The admission of the new Non-UtilityFERC jurisdictional for our 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”). In December 2019, werates, transmission service, and our market based rates. We filed our tariff filings, including our stated rate cost offor wholesale electric service filing, market based rate authorization, and transmission Open Access Transmission Tariff.at FERC in December 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 (“PDO”("Jurisdictional PDO") with FERC, EL20-16-000, asking FERC to confirm our jurisdiction under the FPAFederal Power Act and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission (“COPUC”("COPUC") to address any rate related issues.a 206 proceedingproceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. FERC also rejected our Board Policy 115 (“BP 115”) and member project contracts related to our Utility Member’sMembers’ election to provide up to 5 percent of itstheir electric power requirements pursuant to their wholesale electric service contracts on the grounds that the initial filing was incomplete without Board Policy 101 (“BP 101”) related to the self-supply in excess of the 5 percent annual allowance. The tariff rates were referred to an administrative law judgejudges to encourage settlement of material issues and to hold a hearinghearings if settlementsettlements is not reached. The settlement proceedings are continuing and settlement offers are being exchanged under the FERC administrative law judge’s guidance and in participation with FERC staff. Any refunds to the applicable tariff rates would only apply tofor sales after March 26, 2020. The settlement proceedings for both our Utility Member rates and our transmission service rates are continuing. On April 30,two of our Utility Members proceedingsthe United Power and LPEA proceeding at the COPUC stating they arethe proceeding was not currently preempted.parties.parties, including United Power. On August 28, 2020, FERC issued an order (“August 28 Order”) on rehearing related to our Jurisdictional PDO which modified its March 20, 2020 decision by finding exclusive jurisdiction over our contract termination payments and preempting the jurisdiction of the COPUC as of September 3, 2019 (“August 28 Order”).2019. The August 28 Order also set aside requests for rehearing filed with FERC by other parties related to the Jurisdictional PDO. Requests for rehearing related to FERC’s August 28 Order were filed with FERC by two of our Utility Members.United Power and LPEA. On October 28, 2020, FERC issued an order denying the requests for rehearing filed by two of our Utility Members.RequestsA request for rehearing related to this FERC order has beenwas filed with FERC by one of our Utility Members.23On July 13,United Power. In November 2020, weFERC issued an order addressing the arguments for rehearing raised by United Power and modified its August 28, 2020 order with the same result in the proceeding. United Power has filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit (“("D.C. Circuit Court of Appeals”Appeals") related to FERC’s acceptance of our July 1 filed documents and such matter is being held in abeyance pending resolution of the Jurisdictional PDO appeal discussed below.parties.parties, including United Power. On September 18, 2020, FERC filed to hold the appeals in abeyance. On September 29, 2020, an order was filedissued considering the motion to hold the case in abeyance, directing the parties to file motions to govern future proceedings by January 11, 2021.any requests for rehearing filed with FERC, or our petition for review or any other petitions for review filed with the D.C. Circuit Court of Appeals.Complaint:Complaints: On May 4, 2020, United Power Inc. (“United”) filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court, 2020CV30649, against us and our three Non-Utility Members 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, that we have breached the wholesale electric service contract with United Power, and that we and our three Non-Utility Members conspired to deprive the COPUC of jurisdiction over the contract termination payment of our Colorado Utility Members. On June 20, 2020, we filed our answer denying United’sUnited Power’s allegations and request for relief, and asked the court to dismiss United’sUnited Power’s claims. We asserted counterclaims against United Power, and are seeking relief from United’sUnited Power’s breach of our Bylaws and declaratory judgement that the April 2019 Bylaws amendment and the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are valid. On June 20, 2020, the three Non-Utility Members filed a joint motion to dismiss. United Power filed its response on July 30, 2020. On December 10, 2020, the Non-Utility Members motion to dismiss was granted. On December 23, 2020, United Power sought to amend its May 2020 compliant to add LPEA as an additional plaintiff and to add the claims from its November 2020 complaint, discussed below, into its amended complaint and to dismiss the November 2020 complaint against us. The court has not yet decided whether United Power will be granted leave to file its amended complaint.this matterthese matters or whether we will incur any liability in connection with this matter.24Operations 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.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.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-eight 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.4,317 megawatts, or4,174 MWs, of which approximately 1,0591,166 MWs comes from renewables. In 2019,April 2021, the 104 MW Crossing Trails Wind Farm achieved commercial operation and we began purchasing energy pursuant to a fifteen year power purchase agreement. In 2020, we estimate that nearly a thirdthird of the energy delivered by us and our Utility Members to our Utility Members’ customers came from non-carbon emitting resources.13.44.0 million megawatt hours, or MWhs for the ninethree months ended September 30, 2020,March 31, 2021, of which 91.293.7 percent was to Utility Members. Total revenue from electric sales was $997.6$311.0 million for the ninethree months ended September 30, 2020March 31, 2021 of which 92.987.7 percent was from Utility Member sales. Our results for the ninethree months ended September 30, 2020March 31, 2021 were primarily impacted by seasonal weather changes, including record cold winter weather, as well as reduced sales due to disruptions of operations from our Utility Members’ commercial customers associated with the COVID-19 pandemic.●Utility Member electric sales decreased $15.6 million, or 1.7 percent, primarily due to the withdrawal of a Class A Member in June 2020 and pandemic related issues as many commercial operations continued to be closed or severely reduced.●Fuel expense decreased $38.6 million, or 18.9 percent, primarily due to fluctuations in fuel prices and decreased generation from our generating stations in response to overall decreased demand. Further contributing to decrease in fuel expense, was an environmental obligation related to the New Horizon Mine which was recognized in the prior year.●Production expense decreased $25.9 million, or 17.4 percent, primarily due to the postponement, or selective performance, of scheduled maintenance as a result of impacts from the COVID-19 pandemic.Pursuant to ouris requiredunless otherwise specified in a written agreement or the terms of the Bylaws, to purchase from us the electric power and energy as provided in the Utility Member's contract with us. This contract is the wholesale electric service contract with sucheach Utility Member. OurMember, which is an all-requirements contract. Each wholesale electric service contracts with our 42 Utility Members extend through 2050. These 42 contracts are substantially similar and are subject to automatic extension thereafter until either party provides at least a two years’ notice of its intent to terminate. Each contract25September 30, 2020,March 31, 2021, 20 Utility Members have enrolled in this program with capacity totaling approximately 131138 MWs of which 120126 MWs are in operation. Delta-Montrose Electric Association, or DMEA, withdrew from membership in us in June 2020 and DMEA’s contract was assigned by us to DMEA’s new third-party power supplier.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 are full-requirements transmission Utility Members with the term of all contracts remaining unchanged and continuing to extend through 2050. Class A Members that elect to become Class B members shall be subject toapproved a buy-down payment. In April 2020, the Board approved the terms and conditions forcommunity solar program, a partial requirements structure, including a buy-down payment methodology, and a “Make-Whole” methodology for a Class A Member to become a Class B member that will make othercontract termination payment. Each of these items recommended by the contract committee representing our Utility Members financially whole. In July 2020, wewere filed with the Federal Energy Regulatory Commission, or FERC the Board approved buy-down payment methodology. In September 2020,for approval in 2020. FERC accepted our buy-down payment methodologyeach of these items, subject to refund, and referred itthem to FERC’sFERC's hearing and settlement judge procedures. FERC’s hearing and settlement judge procedures were also consolidated with FERC’s hearing and settlement judge proceduresFor further information see “Item 1 – BUSINESS – MEMBERS – Contract Committee” in our annual report on Form 10-K for our contract termination payment methodology discussed below. In October 2020, our Board approved the partial requirements form contracts and associated partial requirements policies and started the implementation process by providing a ninety-day notice prior to the start of the open season. In January 2021, Utility Members will have approximately one week to express their intent to transition to partial requirements contracts by submitting an application requesting an allocation of the 300 MW system-wide limit. Under the new partial requirements membership construct, Utility Members can request to self-supply up to approximately 50 percent of their load requirements, subject to availability in the open season, in addition to the current 5 percent self-supply provision under the wholesale electric service contract. The capacity available for allocation in the open season represents 10 percent of our system peak demand.Two of our Utility Member filed requests for rehearing. FERC subsequently issued an order denying the twoIn late 2020, certain Utility Members requestsformally requested a contract termination payment amount for rehearing.planning purposes, but have not provided a notice of intent to withdraw. In October 2020, aJanuary 2021, we notified each of these Utility Member filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit related to FERC’s acceptance ofMembers that the contract termination payment methodology.November 2019, La Plata Electric Association, Inc., or LPEA,late February 2021, seven of our Utility Members filed a formal complaint with FERC seeking the Colorado Public Utilities Commission, or COPUC, alleging thatcontract termination payment amount on an expedited basis. In March 2021, we hindered LPEA’s ability to seek withdrawal from us. In November 2019, United Power, Inc., or United, filed a formal complaintmotion to dismiss and answer. In March 2021, our Board approved a contract termination procedures Board policy that that was filed with the COPUC alleging that we hindered United’s abilityFERC for approval. Fourteen interventions of our Utility Members have been filed with FERC related to explore its power supply options by either withdrawing from ussuch Board policy, including three Utility Members filing comments in support and eight Utility Members filing a protest or continuing as a Utility Member under a partial requirements contract. The COPUC consolidated the proceeding. On July 10, 2020, the administrative law judge issued a recommended decision, but the COPUC on its own motion stayed the recommended decision. On October 22, 2020, the COPUC determined that COPUC’s jurisdiction over United and LPEA’s complaints was preempted by FERC and dismissed both complaints without prejudice. See “LEGAL PROCEEDINGS.”Complaintcomplaint for Declaratory Judgementdeclaratory judgement and Damages in the Adams County District Courtdamages against us and our three Non-Utility Members alleging, among other things, that the April 2019 Bylaws amendment that26the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, that we have breached the wholesale electric service contract with United andPower. In November 2020, United Power filed a complaint for declaratory relief against us seeking for the court to declare that we and our threeaddition of the Non-Utility Members conspiredviolated Colorado law. In December 2020, United Power sought to depriveamend its May 2020 compliant to add LPEA as an additional plaintiff and to add the COPUC of jurisdiction overclaims from its November 2020 complaint into its amended complaint and to dismiss the contract termination payment of our Colorado Utility Members. On June 20,November 2020 we filed our answer denying United’s allegations and requestcomplaint against us. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for relief. We asserted counterclaims against United, and requested declaratory judgements on certain matters. On June 20, 2020, the three Non-Utility Members filed a joint motion to dismiss. See “Item 1 - LEGAL PROCEEDINGS” in our quarterly report on Form 10-Q for the three and six months ended June 30, 2020.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. the actions of our Responsible Energy Plan, which will advance our cleaner generation portfolio and programs to serve our Utility Members.clean energy transition. Some of the actionshighlights of the Responsible Energy Plan include:●Reducing emissions by eliminating 100 percent of 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”coal-fired generating facilities in Colorado and New Mexico by 2030.annual report on Form 10-KUtility Members use is expected to come from clean energy.the year ended December 31, 2019.Early Retirements of Generating Facilitiesour Board approvedwe announced the early retirementretirements of Craig Station by 2030 and 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 August 2020, electricity production ended at Escalante Generating Station in New Mexico, and we no longer produce power from coal in New Mexico.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 was approved by FERC during the third quarter of 2020. 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 $430.3 million as of September 30, 2020. The shortened life of Colowyo Mine increases annual depreciation, amortization and depletion expense in the amount of approximately $12.7 million.27global coronavirus (COVID-19)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 reliabilityMembers.Members and decreased sales to our Utility Members and Utility Member revenue due to disruptions of operations from our Utility Members' commercial customers. We continue to monitor the impacts of COVID-19. The full extent to which the COVID-19 pandemic may ultimatelycontinue to impact our results of operations, including the long-term nature of the impacts, depends on numerous evolving factors, which are highly uncertain and difficult to predict, including new information concerning recent increases in casesthe adoption rate of the COVID-19 vaccines, the scope of the recent increases in COVID-19 and the actionstiming to further 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, and we completed two long-term debt transactions in June 2020 with proceeds totaling $225 million. It is reasonably possible, however, that disruption and volatility in the global capital markets may materially increase the cost of capital in the future. The full impact on our results of operations, financial condition, and cash flows cannot be reasonably estimated at this time.requirements. 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 negative rating action by credit rating agencies.September 30, 2020,March 31, 2021, 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.September 30, 2020,March 31, 2021, 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.Indenture. 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 a28Debt Service Ratio (as defined in the Master Indenture), or DSR of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historical and pro forma basis. Our Master Indenture also requires us to maintain an Equity to Capitalization Ratio, or ECR (as defined in the Master Indenture) of at least 18 percent at the end of each fiscal year.$463.2$493.2 million of patronage capital to our Members, including the $47.7 million we retired and DMEA forfeited as part of DMEA’s withdrawal from membership in us on June 30, 2020.was revised in 2018 to establishestablishes a goal of our Board to either defer revenues and incomes as a regulatory liability or recognize previously deferred revenues and incomes (as available) 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 associationorder to better align with the above change, our Board Policy for Financial Goals and Capital Credits was also revisedfinancial goals, we have begun to providerecognize deferred revenue on a quarterly basis when it is reasonably estimable that recognition is required to meet our Board will endeavor to fund an internally restricted cash account for the purposefinancial goals during 2021.At our July 2019 Board meeting, because of increased pressure by 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 non-cooperative members in 2019 and specifically by the addition of MIECO, Inc. as a Non-Utility Member on2019. On the same date,2019, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. In December 2019, we filed with FERC our tariff filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. OnIn March 20, 2020, FERC issued orders regarding our tariff filings. FERC’s orders generally acceptedaccepting our tariff filings, and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactivesubject to September 3, 2019. However, FERC specifically provided that no refunds are duerefund for our Utility Member rates and our transmission service rates prior tosales after March 26, 2020. FERC did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered a 206 proceedingproceedings to determine the justness and reasonableness of our rates, including our Class A wholesale rate schedule (A-40) referenced below, and wholesale electric service contracts. The tariff rates were referred to an administrative law judgejudge to encourage settlement of material issues and to hold a hearing if settlement is not reached. The settlement proceedings are continuing andcontinuing. On April 30, 2021, we filed a proposed settlement offers are being exchanged under the FERC administrative law judge’s guidance and in participationagreement related to our Utility Member stated rate with FERC staff.for approval that provides for us to implement a two-stage, graduated reduction in the charges making up our A-40 rate of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from current rates) thereafter until the date a new Class A fourthwholesale rate schedule goes into effect. This proposed settlement conferenceagreement is scheduled for December 21, 2020. Any refundssubject to FERC’s approval. See Note 17 to the applicable tariff rates would only apply after March 26, 2020. See “LEGAL PROCEEDINGS.”2920192020 and 2020,2021, 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.As approved by our Board in October 2020, the A-40 rate schedule will continue in effect for 2021, subject to the 206 proceeding discussed above. The average budgeted Member cents/kWh for 2021 will remain the same as 2020. For the fifth year in a row, our Class A wholesale rate schedule to our Members have remained unchanged. Our Board also set a goal of reducing our Utility Members rates by eight percent by the end of 2023.toto FERC approval, create new regulatory assets or liabilities or modify the expected recovery period through rates of existing regulatory assets or liabilities. The amounts involved may be material. We continually evaluate options to achieve the goal to lower wholesale rates to our Utility Members.taxes. However,taxes which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in accordance with our regulatory accounting treatment,the consolidated financial statements. Effective January 1, 2020, we adopted the normalization method for recognizing deferred income taxes pursuant to FERC regulation. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability.liability, as approved by our Board. 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.●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; and30●economic conditions.September 30, 2020March 31, 2021 compared to three months ended September 30, 2019lease revenues, coal sales and revenue from supplying steam and water.sales. 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 September 30,March 31, 2021 and 2020 and 2019 (dollars in thousands):Three Months Ended March 31, Period-to-period Change 2021 2020 Amount Percent Operating revenues Utility Member electric sales $ 272,798 $ 292,763 $ (19,965) (6.8) % Non-member electric sales 38,174 15,813 22,361 141.4 % Other 15,000 10,890 4,110 37.7 % Total operating revenues $ 325,972 $ 319,466 $ 6,506 2.0 % Energy sales (in MWh): Utility Member electric sales 3,708,132 4,009,791 (301,659) (7.5) % Non-member electric sales 250,066 306,677 (56,611) (18.5) % 3,958,198 4,316,468 (358,270) (8.3) % ●Utility Member electric sales decreased, in terms of MWhs sold, primarily due to the withdrawal of DMEA in June 2020 and continued economic impacts of COVID-19 during the quarter, in particular, from our Utility Members’ commercial customers. Revenue from Utility Member electric sales also decreased due to a 0.9 percent lower average price during the three months ended September 30, 2020 when compared to the same period in 2019. The decrease in average price was primarily due to decreased demand peak from Utility Members during the three months ended September 30, 2020 when compared to the same period in 2019.●Non-member electric sales increased primarily due to strong open market sales during the three months ended September 30, 2020 when compared to the same period in 2019. While non-member electric sales decreased in terms of MWhs, the average price for the three months ended September 30, 2020 was 51.1 percent higher when compared to the same period in 2019. Increased prices were due in part to impacts from the western fires, causing low production of power in affected states and the need to import replacement power from neighboring states.●Other operating revenues increased primarily due to increased transmission for others.31September 30,March 31, 2021 and 2020 and 2019 (dollars in thousands):Three Months Ended March 31, Period-to-period Change 2021 2020 Amount Percent Operating expenses Purchased power $ 87,017 $ 71,015 $ 16,002 22.5 % Fuel 60,547 61,069 (522) (0.9) % Production 40,901 43,188 (2,287) (5.3) % Transmission 44,671 41,540 3,131 7.5 % General and administrative 14,587 16,215 (1,628) (10.0) % Depreciation, amortization and depletion 52,755 47,024 5,731 12.2 % Coal mining 1,541 2,734 (1,193) (43.6) % Other 2,551 7,683 (5,132) (66.8) % Total operating expenses $ 304,570 $ 290,468 $ 14,102 (0.0)% ●Production expense decreased primarily due to the postponement, or selective performance, of scheduled maintenance as a result of impacts from the COVID-19 pandemic. Maintenance activities are expected to be performed at later dates.●General and administrative expense increased primarily due to an increase in outside professional services, increased regulatory commission costs, 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.NineSeptember 30, 2020March 31, 2021 compared to ninethe same period in 2020. Generation decreased 24.3 percent during the three months ended September 30, 2019Operating RevenuesThe followingMarch 31, 2021 compared to the same period in 2020. Purchased power increased (in MWhs) 20.4 percent for the three months ended March 31, 2021 compared to the same period in 2020. As a result of the mid-February extreme weather event, we incurred approximately $4.9 million in energy imbalance charges from other utilities, which is a comparisoncomponent of our operating revenuespurchased power.energy sales in MWh by type of purchaser fordepletion expense increased primarily due to revisions to asset retirement obligation related to the nine months ended September 30, 2020 and 2019 (dollars in thousands):32●Utility Member electric sales decreased, in terms of MWhs sold, primarily due to the withdrawal of DMEA and a slowdown in certain sectors of the economy from the impacts of COVID-19, in particular, from our Utility Members’ commercial members. Revenue from Utility Member electric sales further decreased due to a half percent lower average price for the nine months ended September 30, 2020 when compared to the same period in 2019. The decrease in average price was primarily due to decreased demand peak from Utility Members during the nine months ended September 30, 2020 when compared to the same period in 2019.●Other operating revenues decreased primarily due to the expiration of leasing arrangement as a lessor on June 30, 2019. Under the agreement, we provided for the use of power generating equipment at the J.M. Shafer Generating Station.Operating ExpensesThe following is a summary of the components of our operating expenses for the nine months ended September 30, 2020 and 2019 (dollars in thousands):●Purchased power expense increased primarily due to favorable market conditions for purchasing power resulting in lower generation from our generating stations. Purchased power increased (in MWhs) 7.2 percent for the nine months ended September 30, 2020 when compared to the same period in 2019. The increase was partially offset by a 4.7 percent decrease in the average price of purchased power during the nine months ended September 30, 2020 when compared to the same period in 2019.●Fuel expense decreased primarily due to lower generation from our generating facilities, fluctuations in fuel prices, and overall decreased demand as a result of more mild weather, and impacts from COVID-19 for the nine months ended September 30, 2020 when compared to the same period in 2019. Also included in fuel expense during the nine months ended September 30, 2019 compared the same period in 2020 was an additional environmental 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.●Production expense decreased primarily due to the postponement, or selective performance, of scheduled maintenance activities as a result of impacts from the COVID-19. Maintenance activities are expected to be performed at later dates.●General and administrative expense increased primarily due to an increase in outside professional services, increased regulatory commission costs, fewer recoveries of general and administrative costs from joint project activities, 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. Additionally, deferred impairment costs related to the Holcomb Generating Station began to be amortized in January 2020.33September 30, 2020March 31, 2021 compared to December 31, 201920192020 to September 30, 2020March 31, 2021 were due to increases and decreases in the following:Assets●Cash and cash equivalents increased $81.9 million, or 98.6 percent, to $165.0 million as of September 30, 2020 compared to $83.1 million as of December 31, 2019. The increase was primarily due to proceeds from the issuance of long-term debt of $425 million ($125 million under our First Mortgage Obligations, Series 2020A with CoBank, ACB, or CoBank, $100 million under our First Mortgage Obligations, Series 2020B with National Rural Utilities Cooperative Finance Corporation, or CFC, and $200 million under our secured revolving credit facility with CFC, as lead arranger and administrative agent, or the Revolving Credit Agreement) and proceeds of $88.5 million related to the DMEA withdrawal. These increases in cash and cash equivalents were partially offset by lower short-term borrowings and higher principal payments of long-term debt.●Restricted cash and investments decreased $25.6 million, or 83.4 percent, to $5.1 million as of September 30, 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.●Regulatory assets increased $219.9 million, or 44.2 percent, to $717.2 million as of September 30, 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 $23.1 million to depreciation, amortization and depletion expense and recovered from our Utility Members through rates.Liabilities●Long-term debt increased $142.6 million, or 4.7 percent, to $3.206 billion as of September 30, 2020 compared to $3.063 billion as of December 31, 2019 and current maturities of long-term debt increased $5.6 million, or 6.9 percent, to $87.2 million as of September 30, 2020 compared to $81.6 million as of December 31, 2019. The total increase of $148.2 million was due to proceeds from issuance of long-term debt of $425.0 million ($125 million from CoBank, $100 million from CFC, and $200 million under our Revolving Credit Agreement) partially offset by debt payments of $277.1 million (primarily $200.0 million for our Revolving Credit Agreement, $37.2 million for the Springerville certificates and $22.0 million for the First Mortgage Obligations, Series 2009C).●Short-term borrowings decreased $252.3 million, or 100.0 percent, to $0 as of September 30, 2020 compared to $252.3 million as of December 31, 2019. 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. On June 24, 2020 we entered into the First Mortgage Obligations, Series 2020A in the amount of $125 million with CoBank as well as the First Mortgage Obligations, Series 2020B in the amount of $100 million with CFC. Proceeds from these two borrowings were used to repay all remaining outstanding commercial paper that came due through July 15, 2020. Additionally, proceeds paid off the remaining Revolving Credit Agreement borrowing in the amount of $125 million that came due on September 24, 2020.●Accrued interest increased $16.1 million, or 54.2 percent, to $45.8 million as of September 30, 2020 compared to $29.7 million as of December 31, 2019. The increase was due to accruals for interest due in future periods of $113.2 million partially offset by interest payments of $97.1 million.●Regulatory liabilities increased $115.0 million, or 94.2 percent, to $237.2 million as of September 30, 2020 compared to $122.2 million as of December 31, 2019. The increase was primarily due to the deferral of the34recognition of $110.2 million of other income and $5.2 million gain on sale of assets in connection with the June 30, 2020 withdrawal of DMEA from membership in us.September 30, 2020,March 31, 2021, we had $165.0$109.5 million in cash and cash equivalents. Our committed credit arrangement as of September 30, 2020March 31, 2021 is as follows (dollars in thousands):Authorized
AmountAvailable
March 31,
2021Revolving Credit Agreement $ 650,000 (1) $ 650,000 (1)The amount of this facility that can be used to support commercial paper is limited to $500 million.September 30, 2020.OnWe had no outstanding borrowings as of March 24, 2020, we borrowed $125 million in LIBOR rate loans under our Revolving Credit Agreement, which was repaid on September 24, 2020.September 30, 2020,March 31, 2021, thereby providing 100 percent dedicated support for any commercial paper outstanding. As of September 30, 2020March 31, 2021, we had no commercial paper outstanding and $500 million available on the commercial paper back-up sublimit.35NineSeptember 30, 2020March 31, 2021 compared to ninethree months ended September 30, 2019$305.9$76.0 million for the ninethree months ended September 30, 20200March 31, 2021 compared to $201.9$65.6 million for the same period in 2019,2020, an increase in net cash provided by operating activities of $104.0$10.4 million. The increase was primarily due to proceedsdeposits associated with generator interconnection requests of $88.5$17.1 million related to the DMEA withdrawalpartially offset by lower net margins including noncontrolling interest, an increase prepayments of annual insurance, memberships and the timing of payment of trade and purchased power payables.$79.3$32.5 million for the ninethree months ended September 30, 2020March 31, 2021 compared to $155.6$42.2 million for the same period in 2019,2020, a decrease in net cash used in investing activities of $76.3$9.7 million. The decrease was primarily due to proceeds from the sale of electric plant related to the DMEA withdrawal and a reduction in generation and transmission improvements and system upgrades for the nine months ended September 30, 2020 compared to the same period in 2019.$170.3$61.3 million for the ninethree months ended September 30, 2020March 31, 2021 compared to $53.5net cash provided by financing activities of $48.7 million for the same period in 2019, an increase2020, a decrease in net cash used in financing activities of $116.8$110.0 million. The increasedecrease was primarily due to higher principal payments of long-term debt of $185.2 million, a decrease in short-term borrowings of $275.4$26.1 million and higher patronage capital retirements to our Members of $49.9 million in 2020 compared to 2019 (on June 30, 2020, we retired $47.7 million of patronage capital in connection with DMEA’s withdrawal from membership in us). These increases in net cash used in financing activities were partially offset by higherlower proceeds from issuance of long-term debt of $390.1 million in 20202021 compared to 20192020 (during the first quarter of 2020, we issued $125 million from the First Mortgage Obligations, Series 2020A, $100 million from the First Mortgage Obligations, Series 2020B andborrowed $200 million from our Revolving Credit Agreement).but without taking into account any changes due to COVID-19, in the years 20202021 through 2024,2025, we forecast that we may invest approximately $877$799 million in new facilities and upgrades to our existing facilities.September 30, 2020,March 31, 2021, we had $3.3 billion in outstanding obligations, including approximately $3.0 billion of debt outstanding secured on a parity basis under our Master Indenture, one unsecured loan agreement totaling $21.5$17.7 million and the Springerville certificates totaling $334.0$293.0 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 (with the exception of one unsecured note), the First Mortgage Obligations, Series 2009C, the First Mortgage Bonds, Series 2010A, the First Mortgage Obligations, Series 2014B, the First Mortgage Bonds, Series 2014E-1 and E-2, First Mortgage Bonds, Series 2016A, First Mortgage Obligations,36system and the Collom pit at Colowyo Mine.20202021 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. and LitigationThe following are recent developments relating to environmental regulations and litigation that may impact us.Collom Air PermitOn July 25, 2018, the Center for Biological Diversity and Sierra Club filed a complaint against the Colorado Department of Public Health and Environment, or the CDPHE, in opposition to CDPHE’s issuance of an air permit for construction and operation of the Collom pit at the Colowyo Mine. On February 14, 2019, the court issued a stay of the case proceedings while CDPHE processed a permit revision. On November 7, 2019, the Collom air permit revision was issued by CDPHE. On December 11, 2019, the Center for Biological Diversity and Sierra Club filed a new case challenging the CDPHE’s issuance of the Collom air permit revision. We filed a motion to intervene as an intervenor-defendant on January 28, 2020. On October 6, 2020, the oral arguments occurred. On October 21, 2020, the judge issued an order affirming the CDPHE’s issuance of the minor source construction air permit to Collom.“Item��Item 1A – RISK FACTORS” in our annual report on Form 10-K for the year ended December 31, 2019.Investors Services, or Moody’s, “A- (negative“BBB+ (stable outlook)” by Standard & Poor’s Global Ratings, or S&P, and “A- (stable outlook)” by Fitch Rating, Inc., or Fitch. Our current short-term ratings are “P-2” by Moody’s, “A-2” by S&P, and “F1” by Fitch.37Off Balance Sheet ArrangementsWe have no off-balance sheet arrangements.2019.legal proceedings disclosed in “Item 3 – LEGAL PROCEEDINGS” in our annual report on Form 10-K for the year ended December 31, 2019 and updatedUnaudited Consolidated Financial Statements in Item 1 – LEGAL PROCEEDINGS” in our quarterly report on Form 10-Q for the three and six months ended June 30, 2020.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 hindered LPEA’s ability to seek withdrawal from us. On November 6, 2019, United filed a formal complaint with the COPUC, alleging that we 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. On November 20, 2019, the COPUC consolidated the two proceeding into one, 19F-0621E.A hearing was held on May 18-20, 2020. On July 10, 2020, the administrative law judge issued a recommended decision, but the COPUC on its own motion stayed the recommended decision. On September 18, 2020, LPEA and United filed a Joint Motion to Lodge FERC’s August 28, 2020 order on rehearing in which FERC reconsidered and modified its March 20, 2020 order finding that the COPUC’s jurisdiction over United and LPEA’s complaints was preempted as of September 3, 2019, and asserting additional corporate law arguments related to the legality of our addition of non-utility members. We filed a response on September 29, 2020. On October 22, 2020, the COPUC38determined that COPUC’s jurisdiction over United and LPEA’s complaints was preempted by FERC, the COPUC does not have jurisdiction over corporate law matters, and dismissed both complaints without prejudice.FERC Tariff and Declaratory Order. Because of increased pressure by states to regulate our rates and charges with impact in other states setting up untenable conflict, we sought consistent federal jurisdiction by FERC. This was accomplished with the addition of non-cooperative members in 2019, specifically MIECO, Inc. as a Non-Utility Member on September 3, 2019. On the same date, 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 in December 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 specifically provided that no refunds are due on 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. FERC also rejected our Board Policy 115, or BP 115, and member project contracts related our Utility Member’s election to provide up to 5 percent of its electric power requirements pursuant to their wholesale electric service contracts on the grounds that the initial filing was incomplete without Board Policy 101, or BP 101, related to the self-supply in excess of the 5 percent annual allowance. 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 and settlement offers are being exchanged under the FERC administrative law judge’s guidance and in participation with FERC staff. Any refunds to the applicable tariff rates would only apply to after March 26, 2020. 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 amount as described in our PDO. Requests for rehearing related to both the PDO and tariff filings were filed with FERC by other parties. On August 28, 2020, FERC issued an order, or the August 28 Order, on rehearing related to our PDO which modified its March 20, 2020 decision by finding exclusive jurisdiction over our contract termination payments and preempting the jurisdiction of the COPUC as of September 3, 2019. The August 28 Order also set aside requests for rehearing filed with FERC by other parties related to the PDO. Requests for rehearing related to FERC’s August 28 Order were filed with FERC by United and LPEA. On October 28, 2020, FERC issued an order denying the requests for rehearing filed by United and LPEA.On July 1, 2020, we re-submitted our BP 101, BP 115, and all existing member project contracts with FERC for acceptance and on August 28, 2020 FERC accepted the filings effective August 31, 2020. FERC also ordered a 206 proceeding to determine whether our July 1 filed documents are just and reasonable and set them for settlement and hearing procedures, which were consolidated with the ongoing settlement and hearing procedures in effect for our member rates docket. FERC also established a refund effective date related to our July 1 filed documents of September 1, 2020. A request for rehearing related to this FERC order has been filed with FERC by United.On July 13, 2020, we filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit, or D.C. Circuit Court of Appeals, to protect our interest, and requested review of FERC’s order granting in part and denying in part our PDO and FERC’s order granting rehearings for further consideration. Petitions for review related to both the PDO and tariff filings have been filed with the D.C. Circuit Court of Appeals by other parties. On September 18, 2020, FERC filed to hold the appeals in abeyance. On September 29, 2020, an order was filed considering the motion to hold the case in abeyance, directing the parties to file motions to govern future proceedings by January 11, 2021.39It is not possible to predict if FERC will require us to refund amounts to our customers for sales after March 26, 2020, if FERC will approve our current practices regarding use of regulatory assets are just and reasonable, or to estimate any liability associated with these matters. In addition, we cannot predict the outcome of the 206 proceedings, any requests for rehearing filed with FERC, or our petition for review or any other petitions for review filed with the D.C. Circuit Court of Appeals.��Exhibit Number Description of Exhibit 10.12.1 Exhibit NumberDescription of Exhibit31.131.2Rule13a-14(a)/15d-14(a)Certification,byPatrick L. Bridges(Principal (Principal FinancialOfficer).40
Association, Inc.November 12, 2020November 12, 202041