UNITEDSTATES
SECURITIESANDEXCHANGECOMMISSION
WASHINGTON,D.C.20549
FORM10-Q
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 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 June 30, 2020 December 31, 2019 ASSETS (unaudited) Property, plant and equipment Electric plant In service $ 6,150,237 $ 6,090,392 Construction work in progress 136,345 164,924 Total electric plant 6,286,582 6,255,316 Less allowances for depreciation and amortization (2,943,957) (2,641,470) Net electric plant 3,342,625 3,613,846 Other plant 414,874 409,051 Less allowances for depreciation, amortization and depletion (127,716) (113,607) Net other plant 287,158 295,444 Total property, plant and equipment 3,629,783 3,909,290 Other assets and investments Investments in other associations 159,157 161,945 Investments in and advances to coal mines 19,626 19,681 Restricted cash and investments 4,948 30,516 Other noncurrent assets 8,741 8,654 Total other assets and investments 192,472 220,796 Current assets Cash and cash equivalents 340,599 83,070 Restricted cash and investments 194 182 Deposits and advances 35,061 28,434 Accounts receivable—Utility Members 116,890 105,371 Other accounts receivable 20,788 28,039 Coal inventory 64,105 50,191 Materials and supplies 93,376 93,632 Total current assets 671,013 388,919 Deferred charges Regulatory assets 725,093 497,279 Prepayment—NRECA Retirement Security Plan 24,176 26,862 Other 52,498 42,672 Total deferred charges 801,767 566,813 Total assets $ 5,295,035 $ 5,085,818 EQUITY AND LIABILITIES Capitalization Patronage capital equity $ 984,221 $ 1,031,063 Accumulated other comprehensive loss (7,781) (1,518) Noncontrolling interest 113,189 111,717 Total equity 1,089,629 1,141,262 Long-term debt 3,216,245 3,063,351 Total capitalization 4,305,874 4,204,613 Current liabilities Utility Member advances 15,128 18,025 Accounts payable 111,508 99,033 Short-term borrowings 139,803 252,323 Accrued expenses 33,240 43,761 Current asset retirement obligations 1,144 2,460 Accrued interest 28,270 29,716 Accrued property taxes 18,822 29,129 Current maturities of long-term debt 210,945 81,555 Total current liabilities 558,860 556,002 Deferred credits and other liabilities Regulatory liabilities 237,304 122,169 Deferred income tax liability 33,969 58,937 Asset retirement and environmental reclamation obligations 81,412 76,454 Other 58,239 56,399 Total deferred credits and other liabilities 410,924 313,959 Accumulated postretirement benefit and postemployment obligations 19,377 11,244 Total equity and liabilities $ 5,295,035 $ 5,085,818 Tri-State Generation and Transmission Association, Inc. Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 Operating revenues Utility Member electric sales $ 286,997 $ 284,658 $ 579,760 $ 583,589 Non-member electric sales 16,625 16,774 32,438 43,504 Other 10,034 13,156 20,924 27,412 313,656 314,588 633,122 654,505 Operating expenses Purchased power 86,653 78,467 157,668 149,423 Fuel 39,549 51,747 100,618 136,897 Production 39,709 52,078 82,897 99,838 Transmission 41,646 40,882 83,186 80,024 General and administrative 16,041 12,096 32,256 22,909 Depreciation, amortization and depletion 44,311 38,144 91,335 76,289 Coal mining 1,087 2,553 3,821 6,149 Other 3,055 3,676 10,738 7,514 272,051 279,643 562,519 579,043 Operating margins 41,605 34,945 70,603 75,462 Other income Interest 984 1,377 2,289 2,792 Capital credits from cooperatives 135 337 3,488 3,334 Other income (expense) 401 631 151 1,912 1,520 2,345 5,928 8,038 Interest expense Interest 37,993 40,111 76,860 80,763 Interest charged during construction (1,601) (2,468) (3,562) (4,839) 36,392 37,643 73,298 75,924 Income tax benefit (121) (77) (330) (154) Net margins including noncontrolling interest 6,854 (276) 3,563 7,730 Net margin attributable to noncontrolling interest (1,421) (1,109) (2,740) (2,126) Net margins attributable to the Association $ 5,433 $ (1,385) $ 823 $ 5,604 Tri-State Generation and Transmission Association, Inc. Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 Net margins including noncontrolling interest $ 6,854 $ (276) $ 3,563 $ 7,730 Other comprehensive loss: Amortization of actuarial loss on postretirement benefit obligation included in net margin 177 (10) 1,110 23 Unrecognized prior service cost — — (7,373) (214) Other comprehensive loss 177 (10) (6,263) (191) Comprehensive income (loss) including noncontrolling interest 7,031 (286) (2,700) 7,539 Net comprehensive income attributable to noncontrolling interest (1,421) (1,109) (2,740) (2,126) Comprehensive income (loss) attributable to the Association $ 5,610 $ (1,395) $ (5,440) $ 5,413 Tri-State Generation and Transmission Association, Inc. Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 Patronage capital equity at beginning of period $ 1,026,453 $ 1,022,743 $ 1,031,063 $ 1,015,754 Net margins attributable to the Association 5,433 (1,385) 823 5,604 Retirement of patronage capital (47,665) — (47,665) — Patronage capital equity at end of period 984,221 1,021,358 984,221 1,021,358 Accumulated other comprehensive income (loss) at beginning of period (7,958) 194 (1,518) 375 Amortization of prior service cost 177 (10) 1,110 23 Unrecognized prior service cost — — (7,373) (214) Accumulated other comprehensive income (loss) at end of period (7,781) 184 (7,781) 184 Noncontrolling interest at beginning of period 111,768 109,732 111,717 110,169 Net comprehensive income attributable to noncontrolling interest 1,421 1,109 2,740 2,126 Equity distribution to noncontrolling interest — — (1,268) (1,454) Noncontrolling interest at end of period 113,189 110,841 113,189 110,841 Total equity at end of period $ 1,089,629 $ 1,132,383 $ 1,089,629 $ 1,132,383 Tri-State Generation and Transmission Association, Inc. Six Months Ended June 30, 2020 2019 Operating activities Net margins including noncontrolling interest $ 3,563 $ 7,730 Adjustments to reconcile net margins to net cash provided by operating activities: Depreciation, amortization and depletion 91,335 76,289 Amortization of intangible asset — 3,662 Amortization of NRECA Retirement Security Plan prepayment 2,686 2,686 Amortization of debt issuance costs 1,204 1,171 Impairment loss 259,761 — Deferred impairment loss and other closure costs (268,163) — Deferred membership withdrawal income 110,165 Capital credit allocations from cooperatives and income from coal mines over refund distributions 2,775 (448) Changes in operating assets and liabilities: Accounts receivable (3,457) 11,889 Coal inventory (13,914) 1,404 Materials and supplies 256 (4,863) Accounts payable and accrued expenses 11,753 5,155 Accrued interest (1,447) (2,290) Accrued property taxes (10,307) (9,508) Other (12,966) (3,688) Net cash provided by operating activities 173,244 89,189 Investing activities Purchases of plant (68,059) (90,913) Sale of electric plant 26,000 — Changes in deferred charges (3,007) 1,538 Proceeds from other investments 68 65 Net cash used in investing activities (44,998) (89,310) Financing activities Changes in Utility Member advances (2,896) (9,357) Payments of long-term debt (142,792) (88,919) Proceeds from issuance of long-term debt 425,000 34,910 Debt issuance costs (527) (13) Increase (decrease) in short-term borrowings, net (112,520) 67,157 Retirement of patronage capital (60,991) (11,101) Equity distribution to noncontrolling interest (1,268) (1,454) Other (279) (257) Net cash provided by (used in) financing activities 103,727 (9,034) Net increase (decrease) in cash, cash equivalents and restricted cash and investments 231,973 (9,155) Cash, cash equivalents and restricted cash and investments – beginning 113,768 127,590 Cash, cash equivalents and restricted cash and investments – ending $ 345,741 $ 118,435 Supplemental cash flow information: Cash paid for interest $ 77,787 $ 82,509 Cash paid for income taxes $ — $ — Supplemental disclosure of noncash investing and financing activities: Change in plant expenditures included in accounts payable $ 594 $ (655) Tri-State Generation and Transmission Association, Inc. On Class A members. See Note 17 – Legal. Jointly Owned Facilities 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 $ 247,959 $ 302 MBPP - Laramie River Station 27.13 % 488,921 300,452 4,363 Total $ 884,020 $ 548,411 $ 4,665 Regulatory assets and liabilities are as follows (dollars in thousands): June 30, December 31, 2020 2019 Regulatory assets Deferred income tax expense (1) $ 33,970 $ 58,937 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 82,569 83,714 Goodwill – J.M. Shafer (3) 47,720 49,145 Goodwill – Colowyo Coal (4) 36,678 37,194 Deferred debt prepayment transaction costs (5) 136,616 140,931 Deferred Holcomb expansion impairment loss (6) 91,157 93,494 Unrecovered plant (7) 296,383 33,864 Total regulatory assets 725,093 497,279 Regulatory liabilities Interest rate swap - realized gain (8) 3,508 3,744 Deferred revenues (9) 75,853 75,853 Membership withdrawal (10) 157,943 42,572 Total regulatory liabilities 237,304 122,169 Net regulatory asset $ 487,789 $ 375,110 June 30, December 31, 2020 2019 Basin Electric Power Cooperative $ 114,036 $ 117,368 National Rural Utilities Cooperative Finance Corporation - patronage capital 11,761 11,761 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,885 15,953 CoBank, ACB 11,141 10,201 Western Fuels Association, Inc. 2,183 2,409 Other 4,151 4,253 Investments in other associations $ 159,157 $ 161,945 June 30, December 31, 2020 2019 Investment in Trapper Mine $ 16,146 $ 15,881 Advances to Dry Fork Mine 3,480 3,800 Investments in and advances to coal mines $ 19,626 $ 19,681 June 30, December 31, 2020 2019 Cash and cash equivalents $ 340,599 $ 83,070 Restricted cash and investments - current 194 182 Restricted cash and investments - noncurrent 4,948 30,516 Cash, cash equivalents and restricted cash and investments $ 345,741 $ 113,768 recognized June 30, December 31, 2020 2019 Accounts receivable - Utility Members $ 116,890 $ 105,371 Other accounts receivable - trade: Non-member electric sales 4,693 4,727 Other 14,862 20,628 Total other accounts receivable - trade 19,555 25,355 Other accounts receivable - nontrade 1,233 2,684 Total other accounts receivable $ 20,788 $ 28,039 Contract liabilities (unearned revenue) $ 6,608 $ 7,041 June 30, December 31, 2020 2019 Preliminary surveys and investigations $ 22,689 $ 21,261 Advances to operating agents of jointly owned facilities 7,085 3,917 Operating lease right-of-use assets 7,925 7,622 Other 14,799 9,872 Total other deferred charges $ 52,498 $ 42,672 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. June 30, December 31, 2020 2019 Total debt $ 3,448,680 3,166,472 Less debt issuance costs (26,735) (27,412) Less debt discounts (9,785) (9,906) Plus debt premiums 15,030 15,752 Total debt adjusted for debt issuance costs, discounts and premiums 3,427,190 3,144,906 Less current maturities (210,945) (81,555) Long-term debt $ 3,216,245 $ 3,063,351 June 30, December 31, 2020 2019 Commercial paper outstanding, net of discounts $ 139,803 $ 252,323 Weighted average interest rate 0.80 % 1.88 % At June 30, 2019 with the other remaining pits still being actively mined. Six Months Ended June 30, 2020 Obligations at beginning of period $ 78,914 Liabilities incurred — Liabilities settled (794) Accretion expense 1,281 Change in cash flow estimate 3,155 Total obligations at end of period $ 82,556 Less current obligations at end of period (1,144) Long-term obligations at end of period $ 81,412 June 30, December 31, 2020 2019 Transmission easements $ 20,148 $ 20,549 Operating lease liabilities - noncurrent 1,813 1,846 Contract liabilities (unearned revenue) - noncurrent 4,030 4,217 Customer deposits 7,558 3,015 Financial liabilities - reclamation 11,112 12,091 Other 13,578 14,681 Total other deferred credits and other liabilities $ 58,239 $ 56,399 The postretirement medical benefit and postemployment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): June 30, 2020 Postretirement medical benefit obligation at beginning of period $ 10,195 Service cost 281 Interest cost 176 Benefit payments (net of contributions by participants) (310) Postretirement medical benefit obligation at end of period $ 10,342 Postemployment medical benefit obligation at end of period 375 Total postretirement and postemployment medical obligations at end of period $ 10,717 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 ceased to add new participants and no new executives will be eligible for the plan. June 30, 2020 Executive benefit restoration obligation at beginning of period $ 674 Service cost 259 Interest cost 354 Plan amendments - prior service cost 5,218 Actuarial loss 2,155 Executive benefit restoration at end of period $ 8,660 The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In 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. 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 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. Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2017 2019 Non-member electric sales: Long-term contracts $ 11,251 $ 10,912 $ 23,395 $ 22,594 Short-term contracts 5,374 5,862 9,043 20,910 Other 10,034 13,156 20,924 27,412 Total non-member electric sales and other operating revenue $ 26,659 $ 29,930 $ 53,362 $ 70,916 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 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): June 30, 2020 Operating leases Operating lease right-of-use assets $ 9,291 Less: Accumulated amortization (1,366) Net operating lease right-of-use assets $ 7,925 Operating lease liabilities - current $ (6,313) Operating lease liabilities - noncurrent (1,813) Total operating lease liabilities $ (8,126) Operating leases Weighted average remaining lease term (years) 9.1 Weighted average discount rate 3.75% Year 1 $ 6,395 Year 2 481 Year 3 351 Year 4 323 Year 5 244 Thereafter 731 Total lease payments $ 8,525 Less imputed interest (399) Total $ 8,126 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: June 30, 2020 December 31, 2019 Estimated Estimated Cost Fair Value Cost Fair Value Marketable securities $ 554 $ 487 $ 715 $ 654 2020. June 30, 2020 December 31, 2019 Principal Estimated Principal Estimated Amount Fair Value Amount Fair Value Total debt $ 3,448,680 $ 4,089,469 $ 3,166,472 $ 3,608,341 June 30, December 31, 2020 2019 Net electric plant $ 767,342 $ 776,411 Noncontrolling interest 113,189 111,717 Long-term debt 342,999 380,867 Accrued interest 9,942 11,050 June 30, June 30, 2020 2019 2020 2019 Depreciation, amortization and depletion $ 4,535 $ 4,535 $ 9,069 $ 9,069 Interest 5,651 5,933 $ 11,511 12,764 NOTE In addition, on November 23, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations South Taylor pit at the Colowyo Mine during the prior year. year ended December 31, 2020. In May 2020, United Power filed a Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for 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 For further information regarding our Responsible Energy Plan, see “Item 1 – BUSINESS — MEMBERS – Responsible Energy Plan” in our annual report on Form 10-K for the year ended December 31, 2020. 2020. 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. December 31, 2021. Unaudited Consolidated Financial Statements in Item 1 for further information. 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. 2020 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 June 30, Three Months Ended June 30, Period-to-period Change 2020 2019 Amount Percent Operating revenues Utility Member electric sales $ 286,997 $ 284,658 $ 2,339 0.8% Non-member electric sales 16,625 16,774 (149) (0.9)% Other 10,034 13,156 (3,122) (23.7)% Total operating revenues $ 313,656 $ 314,588 $ (932) (0.3)% Energy sales (in MWh): Utility Member electric sales 3,725,077 3,734,677 (9,600) (0.3)% Non-member electric sales 337,334 335,592 1,742 0.5% 4,062,411 4,070,269 (7,858) (0.2)% Three Months Ended June 30, Period-to-period Change 2020 2019 Amount Percent Operating expenses Purchased power $ 86,653 $ 78,467 $ 8,186 10.4% Fuel 39,549 51,747 (12,198) (23.6)% Production 39,709 52,078 (12,369) (23.8)% Transmission 41,646 40,882 764 1.9% General and administrative 16,041 12,096 3,945 32.6% Depreciation, amortization and depletion 44,311 38,144 6,167 16.2% Coal mining 1,087 2,553 (1,466) (57.4)% Other 3,055 3,676 (621) (16.9)% Total operating expenses $ 272,051 $ 279,643 $ (7,592) (2.7)% 2020 Six Months Ended June 30, Period-to-period Change 2020 2019 Amount Percent Operating revenues Member electric sales $ 579,760 $ 583,589 $ (3,829) (0.7)% Non-member electric sales 32,438 43,504 (11,066) (25.4)% Other 20,924 27,412 (6,488) (23.7)% Total operating revenues $ 633,122 $ 654,505 $ (21,383) (3.3)% Energy sales (in MWh): Member electric sales 7,734,868 7,768,198 (33,330) (0.4)% Non-member electric sales 644,011 894,660 (250,649) (28.0)% 8,378,879 8,662,858 (283,979) (3.3)% Six Months Ended June 30, Period-to-period Change 2020 2019 Amount Percent Operating expenses Purchased power $ 157,668 $ 149,423 $ 8,245 5.5% Fuel 100,618 136,897 (36,279) (26.5)% Production 82,897 99,838 (16,941) (17.0)% Transmission 83,186 80,024 3,162 4.0% General and administrative 32,256 22,909 9,347 40.8% Depreciation, amortization and depletion 91,335 76,289 15,046 19.7% Coal mining 3,821 6,149 (2,328) (37.9)% Other 10,738 7,514 3,224 42.9% Total operating expenses $ 562,519 $ 579,043 $ (16,524) (2.9)% 2020 •Regulatory liabilities decreased $41.1 million, or 18.3 percent, to $183.9 million as of June 30, 2021 compared to $225.0 million as of December 31, 2020. The decrease was primarily due to the recognition of $40.8 million of previously deferred non-member electric sales revenues. In order to better align with our financial goals, we have begun to recognize deferred revenue on a quarterly basis when it is reasonably estimable that recognition is required to meet our financial goals during 2021. Available Authorized June 30, Amount 2020 Revolving Credit Agreement $ 650,000 (1) $ 385,000 (2) 2021. 2021. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We are mindful of our debt and its maturities and we continually evaluate options to ensure that our balance sheet and capital structure is aligned with our business and the long-term health of our company. 2020 no proceeds in 2021. 2020. 2020. Contractual Commitments 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 “Item 1A – RISK FACTORS” in our annual report on Form 10-K for the year ended December 31, 2020. 32.1 32.2 95 101 XBRL Interactive Data File. Tri-State Generation and Transmission Date: August By: /s/ Duane Highley Duane Highley Chief Executive Officer Date:August /s/ Patrick L. Bridges Patrick L. Bridges Senior Vice President/Chief Financial Officer (Principal Financial Officer)no0 authorized or outstanding equity securities.2020243737373939Abbreviations or Acronyms Definition Basin Basin Electric Power Cooperative Board Board of Directors 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 OATT Open Access Transmission Tariff Revolving Credit Agreement Credit Agreement, dated as of April 25, 2018, between us and CFC, as administrative agent S&P S & P 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.iiJune 30, 2021 December 31, 2020 ASSETS (unaudited) Property, plant and equipment Electric plant In service $ 6,240,314 $ 6,254,652 Construction work in progress 91,093 89,447 Total electric plant 6,331,407 6,344,099 Less allowances for depreciation and amortization (2,985,644) (2,991,393) Net electric plant 3,345,763 3,352,706 Other plant 408,995 456,924 Less allowances for depreciation, amortization and depletion (153,250) (133,012) Net other plant 255,745 323,912 Total property, plant and equipment 3,601,508 3,676,618 Other assets and investments Investments in other associations 164,223 162,975 Investments in and advances to coal mines 2,437 2,799 Restricted cash and investments 4,366 4,682 Other noncurrent assets 15,987 14,889 Total other assets and investments 187,013 185,345 Current assets Cash and cash equivalents 114,494 127,187 Restricted cash and investments 343 205 Deposits and advances 35,932 32,012 Accounts receivable—Utility Members 110,126 96,637 Other accounts receivable 25,513 20,570 Electric plant held for sale Electric plant held for sale 0 4,877 Coal inventory 64,963 55,762 Materials and supplies 82,368 82,119 Total current assets 433,739 419,369 Deferred charges Regulatory assets 688,747 710,268 Prepayment—NRECA Retirement Security Plan 18,803 21,490 Other 41,223 33,646 Total deferred charges 748,773 765,404 Total assets $ 4,971,033 $ 5,046,736 EQUITY AND LIABILITIES Capitalization Patronage capital equity $ 972,473 $ 978,519 Accumulated other comprehensive loss (6,145) (5,714) Noncontrolling interest 115,569 114,851 Total equity 1,081,897 1,087,656 Long-term debt 3,138,826 3,200,181 Total capitalization 4,220,723 4,287,837 Current liabilities Utility Member advances 19,091 16,592 Accounts payable 117,437 98,654 Short-term borrowings 79,968 0 Accrued expenses 29,588 40,736 Current asset retirement obligations 6,679 11,044 Accrued interest 25,892 27,520 Accrued property taxes 18,155 32,794 Current maturities of long-term debt 75,718 87,587 Total current liabilities 372,528 314,927 Deferred credits and other liabilities Regulatory liabilities 183,907 224,953 Deferred income tax liability 19,811 19,591 Asset retirement and environmental reclamation obligations 78,362 127,045 Other 76,351 54,600 Total deferred credits and other liabilities 358,431 426,189 Accumulated postretirement benefit and postemployment obligations 19,351 17,783 Total equity and liabilities $ 4,971,033 $ 5,046,736 Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Operating revenues Utility Member electric sales $ 274,445 $ 286,997 $ 547,243 $ 579,760 Non-member electric sales 36,145 16,625 74,319 32,438 Other 15,712 10,034 30,712 20,924 326,302 313,656 652,274 633,122 Operating expenses Purchased power 86,552 86,653 173,569 157,668 Fuel 45,870 39,549 106,417 100,618 Production 52,841 39,709 93,742 82,897 Transmission 41,948 41,646 86,619 83,186 General and administrative 11,897 16,041 26,484 32,256 Depreciation, amortization and depletion 46,483 44,311 99,238 91,335 Coal mining 966 1,087 2,507 3,821 Other 1,282 3,055 3,833 10,738 287,839 272,051 592,409 562,519 Operating margins 38,463 41,605 59,865 70,603 Other income Interest 907 984 1,784 2,289 Capital credits from cooperatives 2 135 4,275 3,488 Other income Other income 1,032 401 1,889 151 1,941 1,520 7,948 5,928 Interest expense Interest 36,092 37,993 72,207 76,860 Interest charged during construction (1,004) (1,601) (1,978) (3,562) 35,088 36,392 70,229 73,298 Income tax expense (benefit) Income tax expense (benefit) 110 (121) 219 (330) Net margins including noncontrolling interest 5,206 6,854 (2,635) 3,563 Net margin attributable to noncontrolling interest (1,762) (1,421) (3,411) (2,740) Net margins attributable to the Association $ 3,444 $ 5,433 $ (6,046) $ 823 Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Net margins including noncontrolling interest $ 5,206 $ 6,854 $ (2,635) $ 3,563 Other comprehensive income (loss): Unrealized loss on securities available for sale (7) 0 (41) 0 Amortization of actuarial loss on postretirement benefit obligation included in net margin 219 177 731 1,110 Unrecognized prior service cost 0 0 (1,121) (7,373) Other comprehensive income (loss) 212 177 (431) (6,263) Comprehensive income (loss) including noncontrolling interest 5,418 7,031 (3,066) (2,700) Net comprehensive income attributable to noncontrolling interest (1,762) (1,421) (3,411) (2,740) Comprehensive income (loss) attributable to the Association $ 3,656 $ 5,610 $ (6,477) $ (5,440) Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Patronage capital equity at beginning of period $ 969,029 $ 1,026,453 $ 978,519 $ 1,031,063 Net margins attributable to the Association 3,444 5,433 (6,046) 823 Retirement of patronage capital — (47,665) — (47,665) Patronage capital equity at end of period 972,473 984,221 972,473 984,221 Accumulated other comprehensive loss at beginning of period Accumulated other comprehensive loss at beginning of period (6,357) (7,958) (5,714) (1,518) Unrealized loss on securities available for sale Unrealized loss on securities available for sale (7) — (41) — Amortization of prior service cost 219 177 731 1,110 Unrecognized prior service cost — — (1,121) (7,373) Accumulated other comprehensive loss at end of period Accumulated other comprehensive loss at end of period (6,145) (7,781) (6,145) (7,781) Noncontrolling interest at beginning of period 113,807 111,768 114,851 111,717 Net comprehensive income attributable to noncontrolling interest 1,762 1,421 3,411 2,740 Equity distribution to noncontrolling interest — — (2,693) (1,268) Noncontrolling interest at end of period 115,569 113,189 115,569 113,189 Total equity at end of period $ 1,081,897 $ 1,089,629 $ 1,081,897 $ 1,089,629 Six Months Ended June 30, 2021 2020 Operating activities Net margins including noncontrolling interest $ (2,635) $ 3,563 Adjustments to reconcile net margins to net cash provided by operating activities: Depreciation, amortization and depletion 99,238 91,335 Amortization of NRECA Retirement Security Plan prepayment 2,686 2,686 Amortization of debt issuance costs 1,249 1,204 Impairment loss 0 259,761 Deferred impairment loss and other closure costs 0 (268,163) Recognition of deferred revenue Recognition of deferred revenue (40,790) 0 Deferred membership withdrawal income 0 110,165 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 under (over) refund distributions Capital credit allocations from cooperatives and income from coal mines under (over) refund distributions (957) 2,775 Changes in operating assets and liabilities: Accounts receivable (19,250) (3,457) Coal inventory (9,202) (13,914) Materials and supplies (249) 256 Accounts payable and accrued expenses 23,681 11,753 Accrued interest (1,628) (1,447) Accrued property taxes (14,640) (10,307) Other (1,935) (12,966) Net cash provided by operating activities 52,698 173,244 Investing activities Purchases of plant (52,030) (68,059) Sale of electric plant 0 26,000 Changes in deferred charges (5,325) (3,007) Proceeds from other investments 72 68 Net cash used in investing activities (57,283) (44,998) Financing activities Changes in Member advances Changes in Member advances 2,499 (2,896) Payments of long-term debt (73,946) (142,792) Proceeds from issuance of long-term debt 0 425,000 Debt issuance costs 0 (527) Change in short-term borrowings, net Change in short-term borrowings, net 79,968 (112,520) Retirement of patronage capital (13,705) (60,991) Equity distribution to noncontrolling interest (2,693) (1,268) Other (409) (279) Net cash provided by (used in) financing activities (8,286) 103,727 Net increase (decrease) in cash, cash equivalents and restricted cash and investments (12,871) 231,973 Cash, cash equivalents and restricted cash and investments – beginning 132,074 113,768 Cash, cash equivalents and restricted cash and investments – ending $ 119,203 $ 345,741 Supplemental cash flow information: Cash paid for interest $ 72,904 $ 77,787 Cash paid for income taxes $ 0 $ 0 Supplemental disclosure of noncash investing and financing activities: Change in plant expenditures included in accounts payable $ 397 $ 594 20202021 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 June 30, 2020,2021, results of operations for the three and six months ended June 30, 20202021 and 2019,2020, and cash flows for the six months ended June 30, 20202021 and 20192020 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.June 30, 2020, Delta Montrose Electric Association (“DMEA”) withdrew from membership in us pursuantAugust 2, 2021, FERC approved our settlement agreement related to the Membership Withdrawal Agreement. As part of the Membership Withdrawal Agreement, we received $88.5 million in cash, which includes $26 million for the conveyance of certain assets and facilities by usour stated rate to DMEA. In addition, we retired DMEA’s patronage capital balance of $47.7 million, which DMEA subsequently forfeited. The portion of the cash payment not associated with the conveyance of assets and the patronage capital forfeiture resulted in $110.2 million in other income and the conveyance of assets resulted in a $5.2 million gain on the sale of assets. These amounts were deferred by our Board of Directors (“Board”) and are recorded in regulatory liabilities on our consolidated statement of financial position, which is subject to FERC approval. For the fiscal year 2019 and the six months ended June 30, 2020, DMEA constituted approximately 3 percent of our revenue from our Utility Member sales.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.6two2 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.20202021 (dollars in thousands):Tri-State
ShareElectric
Plant in
ServiceAccumulated
DepreciationConstruction
Work In
ProgressYampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 391,698 $ 251,323 $ 653 MBPP - Laramie River Station 27.13 % 500,485 318,715 3,096 Total $ 892,183 $ 570,038 $ 3,749 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.7(1)A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.(2)Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates.(3)Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates.(4)Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members through rates.(5)Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members through rates.(6)Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. Beginning January 2020, the deferred impairment loss is being amortized to other operating expenses in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates.(7)Represents deferral of the impairment losses related to the early retirement of the Nucla and Escalante Generating Stations. In July 2019, our Board took action for the early retirement of the Nucla Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement of the Nucla Generating Station, we recognized an impairment loss of $37.1 million during the third quarter of 2019. On September 19, 2019, the Nucla Generating Station was officially retired from service. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. In January 2020, our Board approved the early retirement of the Escalante Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $268.2 million during the first quarter of 2020. The deferred impairment loss for Escalante Generating Station will be amortized to depreciation, amortization and depletion expense beginning in 2021 through the end of 2045, which was the depreciable life of Escalante Generating Station,8Regulatory assets Deferred income tax expense (1) $ 19,641 $ 19,641 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 80,278 81,424 Goodwill – J.M. Shafer (3) 44,872 46,296 Goodwill – Colowyo Coal (4) 35,645 36,161 Deferred debt prepayment transaction costs (5) 127,988 132,302 Deferred Holcomb expansion impairment loss (6) 86,482 88,819 Unrecovered plant (7) 293,841 305,625 Total regulatory assets 688,747 710,268 Regulatory liabilities Interest rate swap - realized gain (8) and other 3,037 3,293 Deferred revenues (9) 22,927 63,717 Deferred membership withdrawal income (10) 157,943 157,943 Total regulatory liabilities 183,907 224,953 Net regulatory asset $ 504,840 $ 485,315 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 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.Basin 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 Other 6,139 6,385 Investments in other associations $ 164,223 $ 162,975 no0 impairments of these investments recognized during the six months ended June 30, 20202021 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.9Investments in and advances to coal mines are as follows (dollars in thousands):54 – CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTSCash and cash equivalents $ 114,494 $ 127,187 Restricted cash and investments - current 343 205 Restricted cash and investments - noncurrent 4,366 4,682 Cash, cash equivalents and restricted cash and investments $ 119,203 $ 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.2020,2021, we10$0.5$0.7 million of this unearned revenue in other operating revenues on our consolidated statements of operations.Accounts receivable - Utility Members $ 110,126 $ 96,637 Other accounts receivable - trade: Non-member electric sales 7,423 5,231 Other 16,603 9,785 Total other accounts receivable - trade 24,026 15,016 Other accounts receivable - nontrade 1,487 5,554 Total other accounts receivable $ 25,513 $ 20,570 Contract liabilities (unearned revenue) $ 5,598 $ 6,025 76 – OTHER DEFERRED CHARGESPreliminary surveys and investigations $ 12,188 $ 12,886 Advances to operating agents of jointly owned facilities 6,507 2,071 Operating lease right-of-use assets 7,688 7,985 Other 14,840 10,704 Total other deferred charges $ 41,223 $ 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 $23.4$15.8 million as of June 30, 2020.2021. 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 annual112020, we have borrowed $125 million in LIBOR rate loans which are secured under the Revolving Credit Agreement, and issued $140 million in commercial paper against the commercial paper back-up sublimit. As of June 30, 2020,2021, we had $385.0$570.0 million in availability under the Revolving Credit Agreement.On June 24, 2020, we entered into two term loan agreements. A term loan agreement was entered into with CoBank, ACB (“CoBank”) under which we issued our First Mortgage Obligations, Series 2020A consisting of a variable rate borrowing in the amount of $125 million. A term loan agreement was entered into with CFC under which we issued our First Mortgage Obligations, Series 2020B consisting of fixed rate borrowings in the amount of $50 million and variable rate borrowings in the amount of $50 million. Proceeds from the two borrowings were utilized to pay down commercial paper borrowings, repay draws outstanding under the Revolving Credit Agreement and for general corporate purposes.Total debt $ 3,234,768 $ 3,308,715 Less debt issuance costs (24,341) (25,590) Less debt discounts (9,530) (9,659) Plus debt premiums 13,647 14,302 Total debt adjusted for debt issuance costs, discounts and premiums 3,214,544 3,287,768 Less current maturities (75,718) (87,587) Long-term debt $ 3,138,826 $ 3,200,181 98 – SHORT-TERM BORROWINGSCommercial paper outstanding, net of discounts $ 79,968 $ 0 Weighted average interest rate 0.18 % 0 % 2020, $360.02021, $420.0 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 87 – Long-Term Debt.12109 – ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS Mine, and the Fort Union Mine. The New Horizon Mine startedis currently in post-reclamation monitoring. NaN pit at the Colowyo Mine began final reclamation in June 2017. 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.
June 30, 2021Obligations at beginning of period $ 138,089 Liabilities incurred 0 Liabilities settled (135) Accretion expense 1,411 Change in cash flow estimate (54,324) Total obligations at end of period $ 85,041 Less current obligations at end of period (6,679) Long-term obligations at end of period $ 78,362 131110 – OTHER DEFERRED CREDITS AND OTHER LIABILITIESTransmission easements $ 19,531 $ 19,983 Operating lease liabilities - noncurrent 1,689 1,590 Contract liabilities (unearned revenue) - noncurrent 3,520 3,702 Customer deposits 8,900 7,712 Financial liabilities - reclamation 11,931 12,081 Deposits associated with generator interconnection requests Deposits associated with generator interconnection requests 17,130 0 Other 13,650 9,532 Total other deferred credits and other liabilities $ 76,351 $ 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$19.5 and $20.5$20.0 million as of June 30, 20202021 and December 31, 2019,2020, respectively, which are recorded as other deferred credits and other liabilities.1514 – Leases. (unearned1211 – 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 June 30, 2020,2021, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles.14
June 30, 2021Postretirement medical benefit obligation at beginning of period $ 9,985 Service cost 301 Interest cost 129 Benefit payments (net of contributions by participants) (296) Postretirement medical benefit obligation at end of period $ 10,119 Postemployment medical benefit obligation at end of period 419 Total postretirement and postemployment medical obligations at end of period $ 10,538
June 30, 2021June 30, 2020$(1,387)Amortization of actuarial (gain) loss into income11(39)$(1,415)15
June 30, 2021Executive benefit restoration obligation at beginning of period $ 7,379 Service cost 204 Interest cost 109 Actuarial loss 1,121 Executive benefit restoration at end of period $ 8,813 Fair value of plan assets at beginning of period $ 6,955 Employer contributions 806 Actual return on plan assets $ 61 Fair value of plan assets at end of period $ 7,822 Net liability recognized $ 991
June 30, 2021June 30, 2020$(130)Plan amendments - prior service cost(5,218)1,139171 Curtailment and settlement 141 Unrecognized actuarial loss (2,155)$(6,364)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,16Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 Non-member electric sales: Long-term contracts $ 10,093 $ 11,251 $ 18,799 $ 23,395 Short-term contracts 6,096 5,374 14,730 9,043 Recognition of deferred revenue Recognition of deferred revenue 19,956 0 40,790 0 Other 15,712 10,034 30,712 20,924 Total non-member electric sales and other operating revenue $ 51,857 $ 26,659 $ 105,031 $ 53,362 lease revenues, coal sales and revenue from supplying steam and water.revenue. 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, dispatchSteam 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 in17liability.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 provision. This liability method is included in our rate filling accepted by FERC on March 20, 2020; however, FERC may require a different method for the recovery of income taxes. Our consolidated statements of operations included an income tax benefitexpense of $0.3$0.2 million for the six months ended June 30, 20202021 and $0.2an income tax benefit of $0.3 million for the comparable period in 2019. These income tax benefits are due to an alternative minimum tax credit refund.During the three months ended March 31, 2020, we recorded a $19 million decrease in our deferred tax asset valuation allowance due to the deferred tax treatment of an abandonment loss. No changes to the valuation allowance were needed for the three-month period ended June 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.$0.7$0.9 million for the three months ended June 30, 20202021 and $1.8$0.7 million for the comparable period in 2019.2020. Rent expense for all short-term and long-term operating leases was $1.6$1.9 million for the six months ended June 30, 202020, 2021 and $3.6$1.6 million for the comparable period in 2019.2020. Rent expense is included in operating expenses on our consolidated statements of operations. As of June 30, 2020,2021, there were no0 arrangements accounted for as finance leases.18Operating leases Operating lease right-of-use assets $ 9,237 $ 9,223 Less: Accumulated amortization (1,549) (1,238) Net operating lease right-of-use assets $ 7,688 $ 7,985 Operating lease liabilities - current $ (464) $ (526) Operating lease liabilities - noncurrent (1,689) (1,590) Total operating lease liabilities $ (2,153) $ (2,116) Operating leases Weighted average remaining lease term (years) 7.7 7.6 Weighted average discount rate 3.75 % 3.84 % Year 1 $ 550 Year 2 415 Year 3 374 Year 4 247 Year 5 91 Thereafter 650 Total lease payments $ 2,327 Less imputed interest (174) Total $ 2,153 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 $1.6$1.7 million and $4.6$1.6 million for the three months ended June 30, 20202021 and 2019,2020, respectively, and $3.2$3.5 million and $8.9$3.2 million for the six months ended June 30, 20202021 and 2019,2020 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 VALUE19June 30, 2021 December 31, 2020 Cost Estimated
Fair ValueCost Estimated
Fair ValueEBR Trust investments $ 7,822 $ 7,743 $ 6,955 $ 6,955 June 30, 2021 December 31, 2020 Cost Estimated
Fair ValueCost Estimated
Fair ValueMarketable securities $ 513 $ 556 $ 491 $ 478 $249.6$105.9 million as of June 30, 20202021 and $79.0$94.6 million as of December 31, 2019.20June 30, 2021 December 31, 2020 Principal
AmountEstimated
Fair ValuePrincipal
AmountEstimated
Fair ValueTotal long-term debt $ 3,234,768 $ 3,825,737 $ 3,308,715 $ 3,908,497 1716 – VARIABLE INTEREST ENTITIESNet electric plant $ 749,204 $ 758,273 Noncontrolling interest 115,571 114,852 Long-term debt 300,789 342,355 Accrued interest 8,721 9,942 20202021 and 20192020 (dollars in thousands):Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 Depreciation, amortization and depletion $ 4,535 $ 4,535 $ 9,069 $ 9,069 Interest 4,956 5,651 10,141 11,511 Unconsolidated 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 receive coal supplies directly from WFA for the Escalante Generating Station in New Mexico. The pricing structure of the coal supply agreements with WFA is designed to recover the mine operating costs of the mine supplying the coal and therefore the coal sales agreements provide the financial support for the mine operations. There is not sufficient equity at risk for WFA to21finance its activities without additional financial support. Therefore, WFA is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact WFA’s economic performance (acquiring and supplying fuel resources) is held by the members who are represented on the WFA board of directors whose actions require joint approval. Therefore, since there is shared power over the significant activities of WFA, we are not the primary beneficiary of WFA and the entity is not consolidated. Our investment in WFA, accounted for using the cost method, was $2.2 million at June 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 June 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 $16.1 million at June 30, 2020 and $15.9 million at December 31, 2019.1817 – LEGALPursuant to a long-term transmission agreement with another utility, such utility pays for and has firm rights to transfer power and energy across a transmission path in Colorado. Such right to payment and obligation to provide the transfer is borne equally by us and another entity. Due to the current capacity of the transmission path, such utility’s firm rights have been curtailed. The utility disputes its obligation to pay due to the current capacity of the transmission path and claims we, along with the other entity, are in breach of such transmission agreement. The utility notified us and the other entity of its intent to arbitrate in accordance with the agreement and claimed damages caused by the alleged breach of approximately $6.9 million, plus interest, attorney fees, and any future damages. The other entity filed a cross-claim against us claiming we are responsible for such entity’s share of any damages. The matter was scheduled for arbitration to commence in January 2020. The arbitration was 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. It is not possible to predict if FERC will approve this resolution.22AtFERC Tariff and Declaratory Order: 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. The request was made toat FERC to make the new tariffs retroactive to September 3,in December 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. Numerous partiesissues, including the complaints filed interventions or protestsby United Power, Inc. ("United Power") and La Plata Electric Association ("LPEA") with FERC. Some of the interveners and protestors, including some of our Utility Members and the COPUC alleged that we are not FERC jurisdictional and are still exempt from FERC wholesale rate regulation pursuant to the FPA. COPUC.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 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 Members’ election to provide up to 5 percent of their 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. Any refunds to the applicable tariff rates would only apply tofor sales after March 26, 2020. On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including BP 115, BP 101, and Board Policy 119 (“BP 119”), with FERC for approval, as further discussed below. The settlement proceedings for our transmission service rates are continuing. FERC’s March 20, 2020 order regarding our Jurisdictional PDO denied our requested declaration regarding the preemption of the United Power and LPEA proceeding at the COPUC stating the proceeding was not currently preempted.numberamount as described in our Jurisdictional PDO. Requests forOn August 28, 2020, FERC issued an order (“August 28 Order”) on rehearing related to bothour Jurisdictional PDO which modified its March 20, 2020 decision by finding exclusive jurisdiction over our contract termination payments and preempting the PDOjurisdiction of the COPUC as of September 3, 2019.tariff filings have been filedall existing member project contracts with FERC by other parties. Onfor 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 13, 2020, we1 filed documents are just and reasonable and set them for settlement and hearing procedures, which were consolidated with the settlement and hearing procedures in effect for our member rates docket. 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 issued considering the motion to hold the case in abeyance, directing the parties to file motions to govern future proceedings by January 11, 2021. 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. On June 7, 2021, United Power filed its brief with the D.C. Circuit Court of Appeals regarding the Jurisdictional PDO.FERCsettlements will approvebe reached without a hearing on our current practices regarding usetransmission service rates and tariff, or the outcome of regulatory assets are just and reasonable, orthe four reserved issues related to estimate any liability associated with this matter.our member rates docket. In addition, we cannot predict the outcome of the 206 proceedings our April 13 request for rehearing or any other request for rehearing filed with FERC, or our petition for review or any other petitionpetitions for review filed with the D.C. Circuit Court of Appeals. 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. On December 10, 2020, the Non-Utility Members motion to dismiss was granted. On December 23, 2020, United filedPower sought to amend its response onMay 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. On July 2, 2021, the court granted United Power's motion to amend its May 2020 complaint, including to add LPEA as an additional plaintiff and to amend its claims as to our three Non-Utility Members. On July 30, 2020.2021, we filed a partial motion to dismiss a majority of United Power's and LPEA's claims, includingOperations 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.of 4,317 megawatts, orof 4,197 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.8.48.0 million megawatt hours, or MWhs for the six months ended June 30, 2020,2021, of which 92.392.2 percent was to Utility Members. Total revenue from electric sales was $612.2$621.6 million for the six months ended June 30, 2020,2021 of which 94.788.0 percent was from Utility Member sales. Our results for the six months ended June 30, 20202021 were primarily impacted by seasonal weather changes, as well as reducedincluding record cold winter weather in February, and rate stabilization measures.disruptions of operationsreduced membership and a rate reduction in our Utility Member stated rate.Utility Members’ commercial customers associated withgenerating resources because of maintenance activities and favorable market conditions for purchasing power.pandemic.●Non-member electric sales decreased by $11.1 million, or 25.4 percent, primarily due to decreased short-term market sales during the first quarter of 2020 and overall decreased generation from our generating stations.●Fuel expense decreased $36.3 million, or 26.5 percent, primarily due to decreased generation as a result of favorable market conditions for purchasing power.●Production expense decreased $16.9 million, or 17.0 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. We had a wholesale electric service contract with Delta-Montrose Electric Association, or DMEA, that extended through 2040 (which constituted approximately 3 percent of our revenue from Utility Member sales for the six months ended June 30, 2020). DMEA withdrew from membership in us on June 30, 2020 pursuant to the Membership Withdrawal Agreement and DMEA’s contract was assigned by us to DMEA’s new third-party power supplier. These 42 contracts are substantially similar and are subject to automatic extension thereafter24until either party provides at least a two years’ notice of its intent to terminate. Each contract obligates us to sell and deliver to the Utility Member, and obligates the Utility Member to purchase and receive, at least 95 percent of its electric power requirements from us. 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 June 30, 2020, after the withdrawal of DMEA from membership in us,2021, 20 Utility Members have enrolled in this program with capacity totaling approximately 128138 MWs of which 120126 MWs are in operation.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. An annual open season for Class A Members and Class B members will be declared with at least three months of notice withapproved a 300 MW system limit. Class A Members that elect to become Class B members shall be subject tocommunity solar program, a partial requirements structure, including a buy-down payment. In April 2020, the Board approved the termsconditions for a buy-down payment“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 FERC for approval in 2020. FERC accepted each of these items, subject to refund, and referred them to FERC's hearing and settlement judge procedures. During our first "open season" partial requirements nomination period that was completed in May 2021, three Utility Members submitted nominations for an aggregate of 209 MWs of self-supply out of an available pool of 300 MWs. For further information see “Item 1 – BUSINESS – MEMBERS – Contract Committee” in our annual report on Form 10-K for the Federal Energy Regulatory Commission, or FERC, the Board approved buy-down payment methodology.Any termination of a Utility Member wholesale electric service contract shall continue to require Board approval. In April 2010,2020, we filed with FERC the Board approved contract termination payment methodology. In June 2020, FERC accepted our contract termination payment methodology and referred it to FERC’s hearing and settlement judge procedures. TwoIn late 2020, certain Utility Members formally requested a contract termination payment amount for planning purposes. In January 2021, we notified each of these Utility Members that the contract termination payment calculation is time-intensive and complex and that we were working on a contract termination procedure to be filed with FERC. In late February 2021, seven of our Utility MemberMembers filed a complaint with FERC seeking the contract termination payment amount on an expedited basis. In March 2021, we filed a motion to dismiss and answer. In March 2021, our Board approved a contract termination procedures Board policy that was filed with FERC for approval. In May 2021, FERC rejected our proposed contract termination procedures Board policy. In June 2021, FERC issued a show cause order to us regarding our contract termination payment calculation and specifically regarding procedures for our Utility Members to obtain such calculations prior to making their termination decision. A number of our Utility Members and other parties have intervened in such matter. In July 2021, we filed requests for rehearing.On June 30, 2020, DMEA withdrew from membership in us pursuantour response to the Membership Withdrawal Agreement.show cause order and described a plan to file a simpler and more transparent modified contract termination methodology approved by our Board by September 1, 2021. The Membership Withdrawal Agreement providedmodified methodology eliminates our Board discretion over a Utility Member's withdrawal and provides a clear procedure and direct path to obtain a calculation without any delay or fees. The modified methodology continues to protect the financial interests of our remaining Utility Members if a Utility Member elects to withdraw. Our July 2021 filing also included the contract termination payment amount for each of our Utility Members under the paymentmodified contract termination methodology assuming a January 1, 2024 withdraw date. No Utility Member has requested to us by DMEA of $88.5 million, the assignment by us of theterminate its wholesale electric service contract between us and DMEA to DMEA’s new third-party power supplier, the withdrawal of DMEA from membership in us, the retirement by us and forfeiture by DMEA of $47.7 million of DMEA’s patronage capital allocation, and the conveyance of certain assets and facilities by us to DMEA. The $88.5 million in cash, included the $26 million for the conveyance of certain assets and facilities by us to DMEA. The DMEA withdrawal resulted in $110.2 million in other incomeand a $5.2 million gain on the sale of electric plant, which was deferred by our Board and is recorded in deferred credits and other liabilities on the statement of financial position.In November 2019, La Plata Electric Association, Inc., or LPEA, filed a formal complaint with the COPUC alleging that we have hindered LPEA’s ability to seek withdrawal from us. LPEA alleges, among other things, that our Board’s temporary suspension of providing Utility Members with contract termination payment numbers is unlawful. LPEA seeks for the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the contract termination payment amount. In November 2019, United Power, Inc., or United, filed a formal complaint with the COPUC alleging that we have hindered United’s ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory contract termination payment number. United seeks for the COPUC to issue an order establishing a contract termination payment amount. The COPUC has consolidated the proceeding. On July 10, 2020, the administrative law judge issued a recommended decision that followed United’s arguments and adopted United’s contract termination payment methodology to calculate United’s and LPEA’s contract termination payment amount. On July 27, 2020, the COPUC on its own motion stayed the recommended decision. On July 30, 2020, we filed our exceptions (essentially an appeal) to the recommended decision to the full commission of the COPUC. See “LEGAL PROCEEDINGS.”25Complaintcomplaint 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 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 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 complaint against us. In July 2021, the court granted United Power's motion to amend its May 2020 complaint and to add LPEA as an additional plaintiff. In July 2021, we filed our answer denying United’s allegations and request 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 jointpartial motion to dismiss.dismiss the amended May 2020 complaint. In July 2021, United Power's November 2020 complaint was voluntarily dismissed by United Power. See “LEGAL PROCEEDINGS.”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 the first quarter of 2020, in accordance with accounting requirements, we recognized an impairment loss of $268.2 million associated with the early retirement of Escalante Generating Station. Our Board approved the deferral of such impairment loss as a regulatory asset. This loss will be amortized to depreciation, amortization and depletion expense beginning in 2021 through the end of 2045, which was the depreciable life of Escalante Generating Station, and is expected to be recovered from our Utility Members through rates. Such deferral and recovery is subject to approval by FERC. Craig Generating Station Units 2 and 3 continue to be depreciated over the last rate study end lives of 2039 and 2044. Once it becomes probable that FERC will approve the impairment and recovery of unrecovered depreciation associated with the closure of Craig Generating Station Units 2 and 3, then the expected unrecovered depreciation at the time of the closure will be impaired and recovered from our Utility Members through rates. The net book value of Craig Generating Station Units 2 and 3 was $433.4 million as of June 30, 2020. The shortened life of Colowyo Mine increases annual depreciation, amortization and depletion expense in the amount of approximately $12.7 million.ensureachieve the goal to lower wholesale rates to our Utility Member rates remain stable, if not lower, during this transition.Members. A creation of regulatory assets to defer expenses associated with these early retirements or the utilization of regulatory liabilities would require FERC approval.26global 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 reliability of the regional power grid, protecting our employees’ health, and supporting state and national directives to stem the spread of COVID-19 in our communities. We have activated established programs and procedures to mitigate the impacts of pandemics and protect our employees from communicable diseases. Our Crisis Management Team, representing all functions of our operations, is actively assessing potential impacts to our operations and taking actions that mitigate those impacts. These actions include: ensuring our critical generation, transmission and operations teams are staffed and have the resources needed to safely operate our power system; implementing best practices to protect employees from the spread of COVID-19, including achieving social distancing for employees through work from home programs; and postponing in-person meetings with our membership in accordance with public health directives, including delaying our annual membership meeting to August 2020 and holding such meeting virtually. We have also supported COVID-19 pandemic relief and recover funds in each of the four states of our Utility Members, including donations totaling $200,000.In each of our Utility Members states, the governor of such state or officials of certain countiesand communities have implemented various and different measures related to COVID-19, including stay-at-home orders, safer-at-home orders, mandating the closure of certain businesses, and phased re-opening of certain businesses, including re-opening at limited capacity. The various governmental measures are constantly changing and starting to allow for more businesses to re-open.The economic impacts of the COVID-19 pandemic and the various government measures related to COVID-19 have caused a significant slowdown in certain sectors of the economy, including oil and gas, and a corresponding increase in unemployment. Members.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 which may quickly emerge concerning the severityadoption rate of the virus,COVID-19 vaccines, the impact of the delta variant, the scope of the outbreak 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.2020,2021, 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, 2019.2020,2021, we had approximately $3.1$2.9 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 a27Debt 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.was revised in 2018 to establishestablishes a goal of our Board on an annual or quarterly basis 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 increasesIn association with the aboveThis policy, subject to change by our Board, Policy for Financial Goals and Capital Credits was also revised to provide that our Board will endeavor to fund an internally restricted cash accountsets a DSR goal of 1.190 for the purposetwelve months ended December 31, 2021 and a ECR goal of cash funding deferred revenues and incomes held23.5 percent as regulatory liabilities. The amount of cash our Board may internally restrict each year is not based upon the amount of revenue and income deferred.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. Any refundsOn August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate 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 wholesale rate schedule goes into effect. See Note 17 to the applicable tariff rates would only apply after March 26, 2020. See “LEGAL PROCEEDINGS.”20192020 and 2020,2021, our Class A rate schedule (A-40) for electric power sales to our Utility Members consist28taxes. 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“– Factors“Factors Affecting Results – Rates and Regulation” for a description of our energy and demand rates to our Utility Members. Long-term contract sales to non-members generally include energy and demand components. Short-term sales to non-members are sold at market prices after consideration of incremental production costs. Demand billings to non-members are typically billed per kilowatt of capacity reserved or committed to that customer.●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; and●economic conditions.20202021 compared to three months ended June 30, 2019lease revenues, coal sales and revenue from supplying steam and water.sales. Other operating revenue also includes revenue we receive from two of our2920202021 and 20192020 (dollars in thousands):Three Months Ended June 30, Period-to-period Change 2021 2020 Amount Percent Operating revenues Utility Member electric sales $ 274,445 $ 286,997 $ (12,552) (4.4) % Non-member electric sales 36,145 16,625 19,520 117.4 % Other 15,712 10,034 5,678 56.6 % Total operating revenues $ 326,302 $ 313,656 $ 12,646 4.0 % Energy sales (in MWh): Utility Member electric sales 3,661,010 3,725,077 (64,067) (1.7) % Non-member electric sales 368,944 337,334 31,610 9.4 % 4,029,954 4,062,411 (32,457) (0.8) % ●Utility Member electric sales decreased slightly, in terms of MWhs, sold primarily due to a slowdown in certain sectors of the economy from the impacts of COVID-19 during the quarter, in particular, from our Utility Members’ commercial customers. Revenue from Utility Member electric sales increased primarily due to a 1.1 percent higher average price for the three months ended June 30, 2020 when compared to the same period in 2019. The increase in average price was primarily due to increased demand peak from Utility Members during the three months ended June 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.20202021 and 20192020 (dollars in thousands):Three Months Ended June 30, Period-to-period Change 2021 2020 Amount Percent Operating expenses Purchased power $ 86,552 $ 86,653 $ (101) (0.1) % Fuel 45,870 39,549 6,321 16.0 % Production 52,841 39,709 13,132 33.1 % Transmission 41,948 41,646 302 0.7 % General and administrative 11,897 16,041 (4,144) (25.8) % Depreciation, amortization and depletion 46,483 44,311 2,172 4.9 % Coal mining 966 1,087 (121) (11.1) % Other 1,282 3,055 (1,773) (58.0) % Total operating expenses $ 287,839 $ 272,051 $ 15,788 5.8 % ●Purchased power increased primarily due to favorable market conditions for purchasing power resulting in lower generation from our generating stations. Purchased power increased (in MWhs) 12.7 percent for the three months ended June 30, 2020 compared to the same period in 2019. The increase was partially offset by a 2.3 percent decrease in average price of purchased power during the three months ended June 30, 2020 compared to the same period in 2019.●Fuel expense decreased primarily due to lower generation from our generating stations during the period and fluctuation in fuel costs. Net generation (in MWhs) decreased 27.0 percent during the three months ended June 30, 2020 compared to the same period in 2019.●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.20202021 compared to six months ended June 30, 201920202021 and 20192020 (dollars in thousands):●Non-member electric sales decreased primarily due to decreased short-term market sales during the first quarter, decreased demand from impacts of COVID-19, and overall decreased generation from our generating stations. Short-term market sales decreased 284,037 MWhs, or 40.7 percent, to 413,929 MWhs for the six months ended June 30, 2020 compared to 697,966 MWhs for 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.Six Months Ended June 30, Period-to-period Change 2021 2020 Amount Percent Operating revenues Utility Member electric sales $ 547,243 $ 579,760 $ (32,517) (5.6) % Non-member electric sales 74,319 32,438 41,881 129.1 % Other 30,712 20,924 9,788 46.8 % Total operating revenues $ 652,274 $ 633,122 $ 19,152 3.0 % Energy sales (in MWh): Utility Member electric sales 7,369,142 7,734,868 (365,726) (4.7) % Non-member electric sales 619,010 644,011 (25,001) (3.9) % 7,988,152 8,378,879 (390,727) (4.7) % 20202021 and 20192020 (dollars in thousands):31Six Months Ended June 30, Period-to-period Change 2021 2020 Amount Percent Operating expenses Purchased power $ 173,569 $ 157,668 $ 15,901 10.1 % Fuel 106,417 100,618 5,799 5.8 % Production 93,742 82,897 10,845 13.1 % Transmission 86,619 83,186 3,433 4.1 % General and administrative 26,484 32,256 (5,772) (17.9) % Depreciation, amortization and depletion 99,238 91,335 7,903 8.7 % Coal mining 2,507 3,821 (1,314) (34.4) % Other 3,833 10,738 (6,905) (64.3) % Total operating expenses $ 592,409 $ 562,519 $ 29,890 5.3 % ●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) 9.1 percent for the six months ended June 30, 2020 compared to the same period in 2019. The increase was partially offset by a 3.7 percent decrease in the average price of purchased power during the six months ended June 30, 2020 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 seasonal weather changes and impacts from COVID-19. Net generation decreased (in MWhs) 11.5 percent during the six months ended June30, 2020 compared to the same period in 2019. Also included in fuel expense during the six months ended June 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 2020.20202021 compared to December 31, 201920192020 to June 30, 20202021 were due to increases and decreases in the following:Assets●Cash and cash equivalents increased $257.5 million, or 310.0 percent, to $340.6 million as of June 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 cash32Table•Other plant decreased $57.8 million, or 12.4 percent, to $409.0 million as of Contentsequivalents 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 83.8 percent, to $5.1 million as of June 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.●Deposits and advances increased $6.7 million, or 23.3 percent, to $35.1 million as of June 30, 2020 compared to $28.4 million as of December 31, 2019. The increase was primarily due to prepayments of annual insurance,memberships and licenses. These prepayments are being amortized to expense over the tem of the related insurance, membership or license period.●Regulatory assets increased $227.8 million, or 45.8 percent, to $725.1 million as of June 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 $15.4 million to depreciation, amortization and depletion expense and recovered from our Utility Members through rates.Liabilities●Patronage capital equity decreased $46.8 million, or 4.4 percent, to $984.2 million as of June 30, 2020 compared to $1.031 billion as of December 31, 2019. The decrease was primarily due to $47.7 million of patronage capital that we retired in connection with DMEA’s withdrawal from membership in us partially offset by a margin attributable to us of $0.9 million for the six months ended June 30, 2020.●Long-term debt increased $152.9 million, or 5.0 percent, to $3.216 billion as of June 30, 2020 compared to $3.063 billion as of December 31, 2019 and current maturities of long-term debt increased $129.3 million, or 5.3 percent, to $210.9 million as of June 30, 2020 compared to $81.6 million as of December 31, 2019. The total increase of $282.2 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 $142.8 million (primarily $75.0 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 $112.5 million, or 44.6 percent, to $139.8 million as of June 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 are expected to pay off the remaining Revolving Credit Agreement borrowing in the amount of $125 million that will come due on September 24, 2020.●Accrued property taxes decreased $10.3 million, or 35.4 percent, to $18.8 million as of June 30, 2020 compared to $29.1 million as of December 31, 2019. The decrease was due to property tax payments of $29.1 million during 2020 (of which $17.7 million were paid during the second quarter of 2020) partially offset by accruals for property taxes due in future periods of $18.8 million.●Regulatory liabilities increased $115.1 million, or 94.2 percent, to $237.3 million as of June 30, 2020 compared to $122.2 million as of December 31, 2019. The increase was primarily due to the deferral of the recognition 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.33Table•Long-term debt decreased $61.4 million, or 1.9 percent, to $3.139 billion as of Contents2020,2021, we had $340.6$114.5 million in cash and cash equivalents. Our committed credit arrangement as of June 30, 20202021 is as follows (dollars in thousands):Authorized
AmountAvailable
June 30,
2021Revolving Credit Agreement $ 650,000 (1) $ 570,000 (1)The amount of this facility that can be used to support commercial paper is limited to $500 million.(2)The portion of this facility that was unavailable at June 30, 2020 was $265 million which was dedicated to support outstanding commercial paper of $140 million and $125 million in LIBOR rate loans under our Revolving Credit Agreement.$360$420 million of the commercial paper back-up sublimit remained available as of June 30, 2020.AsWe had no outstanding borrowings as of June 30, 2020, we have borrowed $125 million in LIBOR rate loans under our Revolving Credit Agreement, which is expected to be repaid when it comes due in September 2020.2020,2021, thereby providing 100 percent dedicated support for any commercial paper outstanding. WeAs of June 30, 2021, we had $140$80 million of commercial paper outstanding (prior to netting discounts) at June 30, 2020 and $360$420 million available on the commercial paper back-up sublimit at June 30, 2020.On June 24, 2020, we entered into two term loan agreements. A term loan agreement was entered into with CoBank, under which we issued our First Mortgage Obligations, Series 2020A consisting of a variable rate borrowing in the amount of $125 million. A term loan agreement was entered into with CFC under which we issued our First Mortgage Obligations, Series 2020B consisting of fixed rate borrowings in the amount of $50 million and variable rate borrowings in the amount of $50 million. Proceeds from the two borrowings were used to repay all remaining outstanding commercial paper that came due through July 15, 2020 and will be used to repay the remaining Revolving Credit Agreement borrowing in the amount of $125 million coming due on September 24, 2020, and for general corporate purposes.3420202021 compared to six months ended June 30, 2019$173.2$52.7 million for the six months ended June 30, 20202021 compared to $89.2$173.2 million for the same period in 2019, an increase of $84.0 million. The increase2020, a decrease in net cash provided by operating activities of $120.5 million. Substantially all of the decrease was primarily due to proceeds of $88.5 million related to the DMEA withdrawal and the timing of payment of trade and purchased power payables partially offset by a decrease in accounts receivable due2020 compared to lower Utility Member and non-member electric sales.$45.0$57.3 million for the six months ended June 30, 20202021 compared to $89.3$45.0 million for the same period in 2019, a decrease2020, an increase in net cash used in investing activities of $44.3$12.3 million. The decreaseincrease was primarily due to proceeds from the sale of electric plant related to the DMEA withdrawal andin 2020 compared to no proceeds from the sale of electric plant in 2021. Partially offsetting this increase was a reduction in generation and transmission improvements and system upgrades for the six months ended June 30, 20202021 compared to the same period in 2019.provided byused in financing activities was $103.7$8.3 million for the six months ended June 30, 20202021 compared to net cash used in financing activities of $9.0 million for the same period in 2019, an increase in net cash provided by financing activities of $112.7$103.7 million for the same period in 2020, a decrease of $112.0 million. The increase in net cash provided by financing activitiesdecrease was primarily due to higherlower proceeds from issuance of long-term debt ($125in 2021 compared to 2020 (during 2020, we borrowed $125 million from the First Mortgage Obligations, Series 2020A, $100 million from the First Mortgage Obligations, Series 2020B, and $200 million from our Revolving Credit Agreement). These decreases were partially offset by higheran increase in short-term borrowings of $80.0 million and lower principal payments of long-term debt (primarily $75.0 million on our Revolving Credit Agreement), a decrease in short-term borrowings of $179.7 million and higher patronage capital retirements to our Members of $49.9 million in 20202021 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).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.352020,2021, we had $3.6$3.2 billion in outstanding obligations, including approximately $3.1$2.9 billion of debt outstanding secured on a parity basis under our Master Indenture, $140.0$80.0 million in short-term borrowings, one unsecured loan agreement totaling $23.4$15.8 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, 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 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 Litigation2019.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.Off Balance Sheet ArrangementsWe have no off-balance sheet arrangements.362019.As a result of COVID-19, we have activated established programs and procedures to mitigate the impacts of pandemics. While certain of our employees are telecommuting, our business continuity plans have resulted in slight changes to our processes, including how employees access our systems and approve certain work. Management believes it is taking the necessary steps to monitor and maintain appropriate internal controls over financial reporting at this time.legal proceedings disclosed in “Item 3 – LEGAL PROCEEDINGS” in our annual report on Form 10-K for the year ended December 31, 2019and updatedUnaudited Consolidated Financial Statements in Item 1 – LEGAL PROCEEDINGS” in our quarterly report on Form 10-Q for the three months ended March 31, 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 have hindered LPEA’s ability to seek withdrawal from us. LPEA alleges, among other things, that our Board’s temporary suspension of providing Utility Members with a contract termination payment number is unlawful. LPEA seeks the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the contract termination payment amount. On November 6, 2019, United filed a formal complaint with the COPUC, alleging that we have hindered United’s ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory contract termination payment number. United seeks for the COPUC to issue an order establishing a contract termination payment amount. LPEA and United constitute approximately 6 percent and 18 percent, respectively, of our Utility Member revenue for the six months ended June 30, 2020. On November 20, 2019, the COPUC consolidated the two proceeding into one, 19F-0621E. On April 27, 2020, LPEA and United filed a motion for partial summary judgement regarding whether the COPUC has subject matter jurisdiction over the complaints filed by LPEA and United, or in the alternative, that the addition of the Non-Utility Members is invalid under Colorado law. On May 11, 2020, we filed our reply to LPEA and United’s joint motion for partial summary judgement maintaining that issues raised by LPEA and United are matters of Colorado corporate law subject to the exclusive jurisdiction of the state courts and that the admission of Non-Utility Members is not a violation of Colorado law nor of our Articles of Incorporation and Bylaws.An interim decision on May 15, 2020 granted LPEA37and United’s joint motion for partial summary judgment, leaving issues related to the contract termination amount as the only issue to be tried.A hearing was held on May 18-20, 2020 and statements of position were filed on May 28, 2020. On July 10, 2020, the administrative law judge issued a recommended decision that determined that us not providing LPEA and United a contract termination payment number was unjust, unreasonable, and discriminatory and adopted United’s contract termination payment methodology to calculate United’s and LPEA’s contract termination payment amount. The recommended decision references that United’s contract termination payment methodology applied to United would result in a contract termination payment of approximately $234 million. However, the recommended decision provides that a technical conference will be scheduled to update any financial numbers and provide an exact contract termination payment amount. On July 27, 2020, the COPUC on its own motion stayed the recommended decision. On July 30, 2020, we filed our exceptions (essentially an appeal) to the recommended decision. Other entities have also filed exceptions to the recommended decision.FERC Tariff and Declaratory Order. Because of increased pressure by states to regulate our rates and chargeswith 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. The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. The settlement proceedings are continuing. Any refunds to the applicable tariff rates would only apply 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 have been filed with FERC by other parties. On May 14, 2020, FERC entered an order granting our request for rehearing for further consideration on our PDO.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. It 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 this matter. In addition, we cannot predict the outcome of the 206 proceedings, our April 13 request for rehearing or any other request for rehearing filed with FERC, or our petition for review or any other petition for review filed with the D.C. Circuit Court of Appeals.United Adams District Court Complaint. On May 4, 2020, United filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court, 2020CV030649, 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 formula38are also void, that we have breached the wholesale electric service contract with United, 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’s allegations and request for relief, and asked the court to dismiss United’s claims. We asserted counterclaims against United, and are seeking relief from United’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 filed its response on July 30, 2020.It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.Exhibit Number Description of Exhibit 10.3.2 Exhibit NumberDescription4.1.531.131.2Rule13a-14(a)/15d-14(a)Certification,byPatrick L. Bridges(Principal (Principal FinancialOfficer).39
Association, Inc.12, 202012, 202040