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TRI-STATE GENERATION & TRANSMISSION ASSOCIATION, INC. - 10-Q - Management's Discussion and Analysis of Financial Condition and Resultsof Operations

Source: 
Edgar Glimpses

Overview

We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis. We were formed by our utility member systems, or Utility Members, for the purpose of providing wholesale power and transmission services to our Utility Members (which are distribution electric cooperatives and public power districts) for their resale of the power to their retail consumers. Our Utility Members serve large portions of Colorado, Nebraska, New Mexico and Wyoming. We also sell a portion of our generated electric power to other utilities in our regions pursuant to long-term contracts and short-term sale arrangements. Our Utility Members provide retail electric service to suburban and rural residences, farms and ranches, cities, towns and communities, as well as large and small businesses and industries. We are owned entirely by our forty-five members. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. For our forty-two Class A members, or Class A Members, we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members, and therefore all our Utility Members are currently Class A Members. We have three non-utility members, or Non-Utility Members. Our Utility Members and Non-Utility Members are collectively referred to as our "Members." Thirty-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. We supply and transmit our Utility Members' electric power requirements through a portfolio of resources, including generation and transmission facilities, long term purchase contracts and short term energy purchases. We own, lease, have undivided percentage interests in, have tolling arrangements or long-term purchase contracts with respect to, various generating facilities. Our diverse generation portfolio provides us with maximum available power of 4,317 megawatts, or MWs, of which approximately 1,059 MWs comes from renewables. In 2019, we estimate that nearly a third of the energy delivered by us and our Utility Members to our Utility Members' customers came from non-carbon emitting resources. We sold 13.4 million megawatt hours, or MWhs, for the nine months ended September 30, 2020, of which 91.2 percent was to Utility Members. Total revenue from electric sales was $997.6 million for the nine months ended September 30, 2020 of which 92.9 percent was from Utility Member sales. Our results for the nine months ended September 30, 2020 were primarily impacted by seasonal weather changes as well as reduced sales due to disruptions of operations from our Utility Members' commercial customers associated with the COVID-19 pandemic.

Utility Member electric sales decreased $15.6 million, or 1.7 percent,

? primarily due to the withdrawal of a Class A Member in June 2020 and pandemic

related issues as many commercial operations continued to be closed or severely

reduced.

Fuel expense decreased $38.6 million, or 18.9 percent, primarily due to

fluctuations in fuel prices and decreased generation from our generating

? stations in response to overall decreased demand. Further contributing to

decrease in fuel expense, was an environmental obligation related to the New

Horizon Mine which was recognized in the prior year.

Production expense decreased $25.9 million, or 17.4 percent, primarily due to

? the postponement, or selective performance, of scheduled maintenance as a

result of impacts from the COVID-19 pandemic.

Our Bylaws and Wholesale Electric Service Contracts

Pursuant to our Bylaws, each Utility Member is required to purchase from us the electric power and energy provided in the wholesale electric service contract with such Utility Member. Our wholesale electric service contracts with our 42 Utility Members extend through 2050. These 42 contracts are substantially similar and are subject to automatic extension thereafter until either party provides at least a two years' notice of its intent to terminate. Each contract 25

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obligates us to sell and deliver to the Utility Member and obligates the Utility Member to purchase and receive, at least 95 percent of its electric power requirements from us. Each Utility Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled by the Utility Member. As of September 30, 2020, 20 Utility Members have enrolled in this program with capacity totaling approximately 131 MWs of which 120 MWs are in operation. Delta-Montrose Electric Association, or DMEA, withdrew from membership in us in June 2020 and DMEA's contract was assigned by us to DMEA's new third-party power supplier. Pursuant to our wholesale electric service contracts with our Utility Members, we convened a contract committee in 2019 and 2020, consisting of a representative from each Utility Member, to review the wholesale electric service contracts and to discuss alternative contracts for our Utility Members, including partial requirements contracts. Upon recommendations from the contract committee, in March 2020, our Board of Directors, or Board, established two classes of Utility Members: Class A - Utility Full Requirements and Class B - Utility Partial Requirements. Both classes of membership are full-requirements transmission Utility Members with the term of all contracts remaining unchanged and continuing to extend through 2050. Class A Members that elect to become Class B members shall be subject to a buy-down payment. In April 2020, the Board approved the terms and conditions for a buy-down payment methodology for a Class A Member to become a Class B member that will make other Utility Members financially whole. In July 2020, we filed with the Federal Energy Regulatory Commission, or FERC, the Board approved buy-down payment methodology. In September 2020, FERC accepted our buy-down payment methodology and referred it to FERC's hearing and settlement judge procedures. FERC's hearing and settlement judge procedures were also consolidated with FERC's hearing and settlement judge procedures for our contract termination payment methodology discussed below. In October 2020, our Board approved the partial requirements form contracts and associated partial requirements policies and started the implementation process by providing a ninety-day notice prior to the start of the open season. In January 2021, Utility Members will have approximately one week to express their intent to transition to partial requirements contracts by submitting an application requesting an allocation of the 300 MW system-wide limit. Under the new partial requirements membership construct, Utility Members can request to self-supply up to approximately 50 percent of their load requirements, subject to availability in the open season, in addition to the current 5 percent self-supply provision under the wholesale electric service contract. The capacity available for allocation in the open season represents 10 percent of our system peak demand. Pursuant to our Bylaws, a Utility Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe; provided, however, that no Utility Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. In April 2020, the Board approved a "Make-Whole" methodology for a contract termination payment designed to leave remaining Utility Members in the same economic position after a Utility Member terminates its wholesale electric service contract as the remaining Utility Members would have been had the Utility Member not terminated. Any termination of a Utility Member wholesale electric service contract shall continue to require Board approval. In April 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. Two of our Utility Member filed requests for rehearing. FERC subsequently issued an order denying the two Utility Members requests for rehearing. In October 2020, a Utility Member filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit related to FERC's acceptance of the contract termination payment methodology. In November 2019, La Plata Electric Association, Inc., or LPEA, filed a formal complaint with the Colorado Public Utilities Commission, or COPUC, alleging that we hindered LPEA's ability to seek withdrawal from us. In November 2019, United Power, Inc., or United, filed a formal complaint with the COPUC alleging that we hindered United's ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. The COPUC consolidated the proceeding. On July 10, 2020, the administrative law judge issued a recommended decision, but the COPUC on its own motion stayed the recommended decision. On October 22, 2020, the COPUC determined that COPUC's jurisdiction over United and LPEA's complaints was preempted by FERC and dismissed both complaints without prejudice. See "LEGAL PROCEEDINGS." In May 2020, United filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court against us and our three Non-Utility Members alleging, among other things, that the April 2019 Bylaws amendment that 26

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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, 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. We asserted counterclaims against United, and requested declaratory judgements on certain matters. On June 20, 2020, the three Non-Utility Members filed a joint motion to dismiss. See "Item 1 - LEGAL PROCEEDINGS" in our quarterly report on Form 10-Q for the three and six months ended June 30, 2020.

Responsible Energy Plan

In July 2019, we announced that we are pursuing a Responsible Energy Plan to transition to a cleaner generation portfolio while ensuring reliability, increasing Utility Member flexibility, all with a goal to lower wholesale rates to our Utility Members. In January 2020, we announced the actions of our Responsible Energy Plan, which advance our cleaner generation portfolio and programs to serve our Utility Members. Some of the actions of the Responsible Energy Plan include:

Reducing emissions by eliminating 100 percent of emissions from our New Mexico

? coal-fired generating facilities by the end of 2020 and from our Colorado

coal-fired generating facilities by 2030.

Increasing clean energy by bringing over 1 gigawatt of wind and solar resources

? online by 2024, meaning 50 percent of the energy consumed by our Utility

Members' customers is expected to come from renewables by 2024.

? Increasing Utility Member flexibility to develop more local, self-supplied

renewable energy.

? Extending benefits of a clean grid across the economy through expanded electric

vehicle infrastructure and beneficial electrification.

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

Early Retirements of Generating Facilities

As part of our Responsible Energy Plan, in January 2020, our Board approved the early retirement of Escalante Generating Station by the end of 2020 and Craig Generating Station Units 2 and 3 and the Colowyo Mine by 2030. The early retirement of Craig Generating Station Unit 1 by December 31, 2025 remains unchanged. In August 2020, electricity production ended at Escalante Generating Station in New Mexico, and we no longer produce power from coal in New Mexico. In the first quarter of 2020, in accordance with accounting requirements, we recognized an impairment loss of $268.2 million associated with the early retirement of Escalante Generating Station. Our Board approved the deferral of such impairment loss as a regulatory asset. This loss will be amortized to depreciation, amortization and depletion expense beginning in 2021 through the end of 2045, which was the depreciable life of Escalante Generating Station, and is expected to be recovered from our Utility Members through rates. Such deferral and recovery was approved by FERC during the third quarter of 2020. Craig Generating Station Units 2 and 3 continue to be depreciated over the last rate study end lives of 2039 and 2044. Once it becomes probable that FERC will approve the impairment and recovery of unrecovered depreciation associated with the closure of Craig Generating Station Units 2 and 3, then the expected unrecovered depreciation at the time of the closure will be impaired and recovered from our Utility Members through rates. The net book value of Craig Generating Station Units 2 and 3 was $430.3 million as of September 30, 2020. The shortened life of Colowyo Mine increases annual depreciation, amortization and depletion expense in the amount of approximately $12.7 million. In connection with such early retirements, our Board continues to evaluate the creation of additional regulatory assets and use of regulatory liabilities to ensure our Utility Member rates remain stable, if not lower, during this transition. A creation of regulatory assets to defer expenses associated with these early retirements or the utilization of regulatory liabilities would require FERC approval. 27

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COVID-19 Impacts

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

We are intensely focused on safely delivering power to our Utility Members and ensuring the reliability of the regional power grid, protecting our employees' health, and supporting state and national directives to stem the spread of COVID-19 in our communities. We have activated established programs and procedures to mitigate the impacts of pandemics and protect our employees from communicable diseases. Our Crisis Management Team, representing all functions of our operations, is actively assessing potential impacts to our operations and taking actions that mitigate those impacts. These actions include: ensuring our critical generation, transmission and operations teams are staffed and have the resources needed to safely operate our power system; implementing best practices to protect employees from the spread of COVID-19, including achieving social distancing for employees through work from home programs; and postponing in-person meetings with our membership in accordance with public health directives, including 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 counties and 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. 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. We have experienced changes in the load patterns of our Utility Members. We continue to monitor the impacts of COVID-19. The full extent to which the COVID-19 pandemic may ultimately impact our results of operations depends on numerous evolving factors, which are highly uncertain and difficult to predict, including new information concerning recent increases in cases of COVID-19, the scope of the recent increases in COVID-19 and the actions 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. 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.

Critical Accounting Policies

The preparation of our financial statements in conformity with GAAP requires that our management make estimates and assumptions that affect the amounts reported in our consolidated financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. As of September 30, 2020, there were no material changes in our critical accounting policies as disclosed in our annual report on Form 10-K for the year ended December 31, 2019. Factors Affecting Results Master Indenture As of September 30, 2020, we had approximately $3.0 billion of secured indebtedness outstanding under our indenture dated effective as of December 15, 1999, or Master Indenture, between us and Wells Fargo Bank, National Association, as trustee. Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under our Master Indenture. Our Master Indenture requires us to establish rates annually that are reasonably expected to achieve a 28

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Debt Service Ratio (as defined in the Master Indenture), or DSR, of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historical and pro forma basis. Our Master Indenture also requires us to maintain an Equity to Capitalization Ratio, or ECR, (as defined in the Master Indenture) of at least 18 percent at the end of each fiscal year.

Margins and Patronage Capital

We operate on a cooperative basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to meet certain financial requirements and to establish reasonable reserves. Revenues in excess of current period costs in any year are designated as net margins in our consolidated statements of operations. Net margins are treated as advances of capital by our Members and are allocated to our Utility Members on the basis of revenue from electricity purchases from us and to our Non-Utility Members as provided in their respective membership agreement. Our Board Policy for Financial Goals and Capital Credits, approved and subject to change by our Board, sets guidelines to achieve margins and retain patronage capital sufficient to maintain a sound financial position and to allow for the orderly retirement of capital credits allocated to our Utility Members. On a periodic basis, our Board will determine whether to retire any patronage capital, and in what amounts, to our Members. To date, we have retired approximately $463.2 million of patronage capital to our Members, including the $47.7 million we retired and DMEA forfeited as part of DMEA's withdrawal from membership in us on June 30, 2020. Pursuant to our Board Policy for Financial Goals and Capital Credits, we set rates to achieve a DSR and ECR in excess of the requirements under our Master Indenture in order to mitigate the risk of potential negative variances between budgeted margins and actual margins. This policy was revised in 2018 to establish a goal of our Board to either defer revenues and incomes as a regulatory liability or recognize previously deferred revenues and incomes in an amount that will result in a DSR equal to a DSR goal for the applicable year as set forth in the policy. As allowed by our Bylaws, the deferral or recognition of previously deferred revenues and income is for the purpose of stabilizing margins and limiting rate increases from year to year. In association with the above change, our Board Policy for Financial Goals and Capital Credits was also revised to provide that our Board will endeavor to fund an internally restricted cash account for the purpose of cash funding deferred revenues and incomes held as regulatory liabilities. The amount of cash our Board may internally restrict each year is not based upon the amount of revenue and income deferred.

Rates and Regulation

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 on September 3, 2019. On the same date, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. In December 2019, we filed our tariff filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. On March 20, 2020, FERC issued orders regarding our tariff filings. FERC's orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC specifically provided that no refunds are due for our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered a 206 proceeding to determine the justness and reasonableness of our rates, including our Class A wholesale rate schedule referenced below, and wholesale electric service contracts. The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. The settlement proceedings are continuing and settlement offers are being exchanged under the FERC administrative law judge's guidance and in participation with FERC staff. A fourth settlement conference is scheduled for December 21, 2020. Any refunds to the applicable tariff rates would only apply after March 26, 2020. See "LEGAL PROCEEDINGS." Our electric sales revenues are derived from electric power sales to our Utility Members and non-member purchasers. Revenues from electric power sales to our non-member purchasers is pursuant to our market based rate authority. 29

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Revenues from electric power sales to our Utility Members are primarily from our Class A wholesale rate schedule filed with FERC. In 2019 and 2020, our Class A rate schedule (A-40) for electric power sales to our Utility Members consist of three billing components: an energy rate and two demand rates. Utility Member rates for energy and demand are set by our Board, consistent with the provision of reliable cost-based supply of electricity over the long term to our Utility Members. Energy is the physical electricity delivered to our Utility Members. The energy rate was billed based upon a price per kWh of physical energy delivered and the two demand rates (a generation demand and a transmission/delivery demand) were both billed based on the Utility Member's highest thirty-minute integrated total demand measured in each monthly billing period during our peak period from noon to 10:00 pm daily, Monday through Saturday, with the exception of six holidays. Our Class A rate schedule (A-40) was filed at FERC as a "stated rate." While our Board still has authority to determine our rates, those rates, including any change to the rate or rate structure, must be approved by FERC subject to outside comments. As approved by our Board in October 2020, the A-40 rate schedule will continue in effect for 2021, subject to the 206 proceeding discussed above. The average budgeted Member cents/kWh for 2021 will remain the same as 2020. For the fifth year in a row, our Class A wholesale rate schedule to our Members have remained unchanged. Our Board also set a goal of reducing our Utility Members rates by eight percent by the end of 2023. Our Board may from time to time, subject to FERC approval, create new regulatory assets or liabilities or modify the expected recovery period through rates of existing regulatory assets or liabilities. The amounts involved may be material. We continually evaluate options to achieve the goal to lower wholesale rates to our Utility Members. Tax Status We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes. However, in accordance with our regulatory accounting treatment, changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues. Under this regulatory accounting approach, any income tax expense or benefit on our consolidated statements of operations includes only the current portion. Results of Operations General Our electric sales revenues are derived from electric power sales to our Utility Members and non-member purchasers. See "- Factors Affecting Results - Rates and Regulation" for a description of our energy and demand rates to our Utility Members. Long-term contract sales to non-members generally include energy and demand components. Short-term sales to non-members are sold at market prices after consideration of incremental production costs. Demand billings to non-members are typically billed per kilowatt of capacity reserved or committed to that customer. Weather has a significant effect on the usage of electricity by impacting both the electricity used per hour and the total peak demand for electricity. Consequently, weather has a significant impact on our revenues. Relatively higher summer or lower winter temperatures tend to increase the usage of electricity for heating, air conditioning and irrigation. Mild weather generally reduces the usage of electricity because heating, air conditioning and irrigation systems are operated less frequently. The amount of precipitation during the growing season (generally May through September) also impacts irrigation use. Other factors affecting our Utility Members' usage of electricity include:

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

? the expansion of operations among our Utility Members' commercial and

industrial customers;

? the general growth in population;

? COVID-19 and governmental orders related to COVID-19; and

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Table of Contents ? economic conditions.

Three months ended September 30, 2020 compared to three months ended September 30, 2019

Operating Revenues

Our operating revenues are primarily derived from electric power sales to our Utility Members and non-member purchasers. Other operating revenue consists primarily of wheeling, transmission and lease revenues, coal sales and revenue from supplying steam and water. Other operating revenue also includes revenue we receive from two of our Non-Utility Members. The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the three months ended September 30, 2020 and 2019 (dollars in thousands): Three Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating revenues Utility Member electric sales $ 346,769 $ 358,586 $ (11,817) (3.3)% Non-member electric sales 38,606 28,339 10,267 36.2% Other 16,226 12,128 4,098 33.8% Total operating revenues $ 401,601 $ 399,053 $ 2,548 0.6% Energy sales (in MWh): Utility Member electric sales 4,512,087 4,625,494 (113,407) (2.5)% Non-member electric sales 533,360 549,427 (16,067) (2.9)% 5,045,447 5,174,921 (129,474) (2.5)%

Utility Member electric sales decreased, in terms of MWhs sold, primarily due

to the withdrawal of DMEA in June 2020 and continued economic impacts of

COVID-19 during the quarter, in particular, from our Utility Members'

commercial customers. Revenue from Utility Member electric sales also decreased

? due to a 0.9 percent lower average price during the three months ended

September 30, 2020 when compared to the same period in 2019. The decrease in

average price was primarily due to decreased demand peak from Utility Members

during the three months ended September 30, 2020 when compared to the same

period in 2019.

Non-member electric sales increased primarily due to strong open market sales

during the three months ended September 30, 2020 when compared to the same

period in 2019. While non-member electric sales decreased in terms of MWhs, the

? average price for the three months ended September 30, 2020 was 51.1 percent

higher when compared to the same period in 2019. Increased prices were due in

part to impacts from the western fires, causing low production of power in

affected states and the need to import replacement power from neighboring

states.

? Other operating revenues increased primarily due to increased transmission for

others. Operating Expenses Our operating expenses are primarily comprised of the costs that we incur to supply and transmit our Utility Members' electric power requirements through a portfolio of resources, including generation and transmission facilities, long-term purchase contracts and short-term energy purchases and the costs associated with any sales of power to non-members. 31

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The following is a summary of the components of our operating expenses for the three months ended September 30, 2020 and 2019 (dollars in thousands):

Three Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating expenses Purchased power $ 103,136 $ 103,525 $ (389) (0.4)% Fuel 65,061 67,374 (2,313) (3.4)% Production 39,698 48,619 (8,921) (18.3)% Transmission 43,989 42,305 1,684 4.0% General and administrative 17,081 12,978 4,103 31.6% Depreciation, amortization and depletion 45,775 40,590 5,185 12.8% Coal mining 4,200 1,675 2,525 150.7% Other 2,691 4,640 (1,949) (42.0)% Total operating expenses $ 321,631 $ 321,706 $ (75) (0.0)%

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.

Nine months ended September 30, 2020 compared to nine months ended September 30, 2019

Operating Revenues

The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the nine months ended September 30, 2020 and 2019 (dollars in thousands):

Nine Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating revenues Member electric sales $ 926,529 $ 942,175 $ (15,646) (1.7)% Non-member electric sales 71,044 71,843 (799) (1.1)% Other 37,150 39,540 (2,390) (6.0)% Total operating revenues $ 1,034,723 $ 1,053,558 $ (18,835) (1.8)% Energy sales (in MWh): Member electric sales 12,246,955 12,393,692 (146,737) (1.2)% Non-member electric sales 1,177,370 1,444,087 (266,717) (18.5)% 13,424,325 13,837,779 (413,454) (3.0)% 32

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Utility Member electric sales decreased, in terms of MWhs sold, primarily due

to the withdrawal of DMEA and a slowdown in certain sectors of the economy from

the impacts of COVID-19, in particular, from our Utility Members' commercial

? members. Revenue from Utility Member electric sales further decreased due to a

half percent lower average price for the nine months ended September 30, 2020

when compared to the same period in 2019. The decrease in average price was

primarily due to decreased demand peak from Utility Members during the nine

months ended September 30, 2020 when compared to the same period in 2019.

Other operating revenues decreased primarily due to the expiration of leasing

? arrangement as a lessor on June 30, 2019. Under the agreement, we provided for

the use of power generating equipment at the J.M. Shafer Generating Station.

Operating Expenses

The following is a summary of the components of our operating expenses for the nine months ended September 30, 2020 and 2019 (dollars in thousands):

Nine Months Ended September 30, Period-to-period Change 2020 2019 Amount Percent Operating expenses Purchased power $ 260,804 $ 252,948 $ 7,856 3.1% Fuel 165,679 204,271 (38,592) (18.9)% Production 122,595 148,457 (25,862) (17.4)% Transmission 127,175 122,329 4,846 4.0% General and administrative 49,337 35,887 13,450 37.5% Depreciation, amortization and depletion 137,110 116,879 20,231 17.3% Coal mining 8,021 7,824 197 2.5% Other 13,429 12,154 1,275 10.5% Total operating expenses $ 884,150 $ 900,749 $ (16,599) (1.8)%

Purchased power expense increased primarily due to favorable market conditions

for purchasing power resulting in lower generation from our generating

stations. Purchased power increased (in MWhs) 7.2 percent for the nine months

? ended September 30, 2020 when compared to the same period in 2019. The increase

was partially offset by a 4.7 percent decrease in the average price of

purchased power during the nine months ended September 30, 2020 when compared

to the same period in 2019.

Fuel expense decreased primarily due to lower generation from our generating

facilities, fluctuations in fuel prices, and overall decreased demand as a

result of more mild weather, and impacts from COVID-19 for the nine months

ended September 30, 2020 when compared to the same period in 2019. Also

? included in fuel expense during the nine months ended September 30, 2019

compared the same period in 2020 was an additional environmental obligation of

$9.9 million due to the anticipated revision to the New Horizon Mine

reclamation plan to accommodate an alternative post mine land use, including

construction of a pond, necessary for final mine reclamation.

Production expense decreased primarily due to the postponement, or selective

? performance, of scheduled maintenance activities as a result of impacts from

the COVID-19. Maintenance activities are expected to be performed at later

dates.

General and administrative expense increased primarily due to an increase in

outside professional services, increased regulatory commission costs, fewer

? recoveries of general and administrative costs from joint project activities,

as well as an overall increase in expenses related to general and administration labor and benefits.

Depreciation, amortization, and depletion expense increased primarily due to

increased depreciation related to the Collom development, accelerated depletion

? on the coal reserves at the Colowyo Mine and a change in asset depreciable

lives from 2044 to 2030 as a result of the planned early retirement of the

Colowyo Mine. Additionally, deferred impairment costs related to the Holcomb

Generating Station began to be amortized in January 2020. 33

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Financial condition as of September 30, 2020 compared to December 31, 2019

The principal changes in our financial condition from December 31, 2019 to September 30, 2020 were due to increases and decreases in the following:

Assets Cash and cash equivalents increased $81.9 million, or 98.6 percent, to $165.0 million as of September 30, 2020 compared to $83.1 million as of

December 31, 2019. The increase was primarily due to proceeds from the issuance

of long-term debt of $425 million ($125 million under our First Mortgage

Obligations, Series 2020A with CoBank, ACB, or CoBank, $100 million under our

? First Mortgage Obligations, Series 2020B with National Rural Utilities

Cooperative Finance Corporation, or CFC, and $200 million under our secured

revolving credit facility with CFC, as lead arranger and administrative agent,

or the Revolving Credit Agreement) and proceeds of $88.5 million related to the

DMEA withdrawal. These increases in cash and cash equivalents were partially

offset by lower short-term borrowings and higher principal payments of long-term debt.

Restricted cash and investments decreased $25.6 million, or 83.4 percent, to

$5.1 million as of September 30, 2020 compared to $30.7 million as of

? December 31, 2019. The decrease was primarily due to the unrestricting by our

Board of restricted cash related to deferred revenue in response to volatile

market conditions.

Regulatory assets increased $219.9 million, or 44.2 percent, to $717.2 million

as of September 30, 2020 compared to $497.3 million as of December 31, 2019.

The increase was primarily due to the deferral of the $268.2 million impairment

loss (including $259.8 million of impaired assets and $8.4 million of deferred

? severance) related to the early retirement of the Escalante Generating Station,

which is expected to be retired by the end of 2020. This increase was partially

offset by a decrease of $25.0 million in the deferred income tax valuation

allowance related to the Holcomb abandonment tax loss and amortization of

$23.1 million to depreciation, amortization and depletion expense and recovered

from our Utility Members through rates. Liabilities

Long-term debt increased $142.6 million, or 4.7 percent, to $3.206 billion as

of September 30, 2020 compared to $3.063 billion as of December 31, 2019 and

current maturities of long-term debt increased $5.6 million, or 6.9 percent, to

$87.2 million as of September 30, 2020 compared to $81.6 million as of

December 31, 2019. The total increase of $148.2 million was due to proceeds

? from issuance of long-term debt of $425.0 million ($125 million from CoBank,

$100 million from CFC, and $200 million under our Revolving Credit Agreement)

partially offset by debt payments of $277.1 million (primarily $200.0 million

for our Revolving Credit Agreement, $37.2 million for the Springerville

certificates and $22.0 million for the First Mortgage Obligations, Series

2009C).

Short-term borrowings decreased $252.3 million, or 100.0 percent, to $0 as of

September 30, 2020 compared to $252.3 million as of December 31, 2019. The

decrease was due to a temporary market disruption in the commercial paper

market which began around March 16, 2020 and continued through early April.

During that period of time which saw elevated Tier 2 borrowing rates and

shortened tenors, we borrowed under our Revolving Credit Agreement in the

? amount of $200 million and paid down the commercial paper by $200 million. On

June 24, 2020 we entered into the First Mortgage Obligations, Series 2020A in

the amount of $125 million with CoBank as well as the First Mortgage

Obligations, Series 2020B in the amount of $100 million with CFC. Proceeds from

these two borrowings were used to repay all remaining outstanding commercial

paper that came due through July 15, 2020. Additionally, proceeds paid off the

remaining Revolving Credit Agreement borrowing in the amount of $125 million

that came due on September 24, 2020.

Accrued interest increased $16.1 million, or 54.2 percent, to $45.8 million as

? of September 30, 2020 compared to $29.7 million as of December 31, 2019. The

increase was due to accruals for interest due in future periods of

$113.2 million partially offset by interest payments of $97.1 million.

Regulatory liabilities increased $115.0 million, or 94.2 percent, to

? $237.2 million as of September 30, 2020 compared to $122.2 million as of

December 31, 2019. The increase was primarily due to the deferral of the

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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.

Liquidity and Capital Resources

We finance our operations, working capital needs and capital expenditures from operating revenues and issuance of short-term and long-term borrowings. As of September 30, 2020, we had $165.0 million in cash and cash equivalents. Our committed credit arrangement as of September 30, 2020 is as follows (dollars in thousands): Available Authorized September 30, Amount 2020 Revolving Credit Agreement $ 650,000 (1) $ 650,000

(1) The amount of this facility that can be used to support commercial paper is

limited to $500 million. We have a secured Revolving Credit Agreement with aggregate commitments of $650 million. The Revolving Credit Agreement includes a swingline sublimit of $100 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million, of which $100 million of the swingline sublimit, $75 million of the letter of credit sublimit, and $500 million of the commercial paper back-up sublimit remained available as of September 30, 2020. The Revolving Credit Agreement is secured under the Master Indenture and has a maturity date of April 25, 2023, unless extended as provided therein. Funds advanced under the Revolving Credit Agreement are either LIBOR rate loans or base rate loans, at our option. LIBOR rate loans bear interest at the adjusted LIBOR rate for the term of the advance plus a margin (currently 1.125 percent) based on our credit ratings. Base rate loans bear interest at the alternate base rate plus a margin (currently 0.125 percent) based on our credit ratings. The alternate base rate is the highest of (a) the federal funds rate plus ½ of 1.00 percent, (b) the prime rate, and (c) the one-month LIBOR rate plus 1.00 percent. Upon discontinuation of the LIBOR rate, the Revolving Credit Agreement provides for CFC and us to endeavor to establish an alternative rate that gives due consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States. Upon discontinuation of the LIBOR rate and if no alternative rate has been established by CFC and us, all funds advances will be at base rate loans. On March 24, 2020, we borrowed $125 million in LIBOR rate loans under our Revolving Credit Agreement, which was repaid on September 24, 2020. The Revolving Credit Agreement contains customary representations, warranties, covenants, events of default and acceleration, including financial DSR and ECR requirements in line with the covenants contained in our Master Indenture. A violation of these covenants would result in the inability to borrow under the facility. Under our commercial paper program, our Board authorized us to issue commercial paper in amounts that do not exceed the commercial paper back-up sublimit under our Revolving Credit Agreement, which was $500 million at September 30, 2020, thereby providing 100 percent dedicated support for any commercial paper outstanding. As of September 30, 2020, we had no commercial paper outstanding and $500 million available on the commercial paper back-up sublimit. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We are mindful of our debt and its maturities and we continually evaluate options to ensure that our balance sheet and capital structure is aligned with our business and the long-term health of our company.

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

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Cash Flow

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

Nine months ended September 30, 2020 compared to nine months ended September 30, 2019

Operating activities. Net cash provided by operating activities was $305.9 million for the nine months ended September 30, 20200 compared to $201.9 million for the same period in 2019, an increase in net cash provided by operating activities of $104.0 million. The increase 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.

Investing activities. Net cash used in investing activities was $79.3 million for the nine months ended September 30, 2020 compared to $155.6 million for the same period in 2019, a decrease in net cash used in investing activities of $76.3 million. The decrease was primarily due to proceeds from the sale of electric plant related to the DMEA withdrawal and a reduction in generation and transmission improvements and system upgrades for the nine months ended September 30, 2020 compared to the same period in 2019. Financing activities. Net cash used in financing activities was $170.3 million for the nine months ended September 30, 2020 compared to $53.5 million for the same period in 2019, an increase in net cash used in financing activities of $116.8 million. The increase was primarily due to higher principal payments of long-term debt of $185.2 million, a decrease in short-term borrowings of $275.4 million and higher patronage capital retirements to our Members of $49.9 million in 2020 compared to 2019 (on June 30, 2020, we retired $47.7 million of patronage capital in connection with DMEA's withdrawal from membership in us). These increases in net cash used in financing activities were partially offset by higher proceeds from issuance of long-term debt of $390.1 million in 2020 compared to 2019 (during 2020, we issued $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). Capital Expenditures We forecast our capital expenditures annually as part of our long-term planning. We regularly review these projections to update our calculations to reflect changes in our future plans, facility closures, facility costs, market factors and other items affecting our forecasts. After taking into account our Responsible Energy Plan, but without taking into account any changes due to COVID-19, in the years 2020 through 2024, we forecast that we may invest approximately $877 million in new facilities and upgrades to our existing facilities. Our actual capital expenditures depend on a variety of factors, including assumptions related to our Responsible Energy Plan, Utility Member load growth, availability of necessary permits, regulatory changes, environmental requirements, construction delays and costs, and ability to access capital in credit markets. Thus, actual capital expenditures may vary significantly from our projections.

Capital projects include several transmission projects to improve reliability and load-serving capability throughout our service area.

Contractual Commitments

Indebtedness. As of September 30, 2020, we had $3.3 billion in outstanding obligations, including approximately $3.0 billion of debt outstanding secured on a parity basis under our Master Indenture, one unsecured loan agreement totaling $21.5 million and the Springerville certificates totaling $334.0 million (which are secured only by a mortgage and lien on Springerville Unit 3 and the Springerville lease). Our debt secured by the lien of our Master Indenture includes notes payable to CFC and CoBank (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, 36

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

Construction Obligations. We have commitments to complete certain construction projects associated with improving the reliability of the generating facilities and the transmission system and the Collom pit at Colowyo Mine. Coal Purchase Obligations. We have commitments to purchase coal for our generating facilities under long-term contracts that expire between 2020 and 2041. These contracts require us to purchase a minimum quantity of coal at prices that are subject to escalation clauses that reflect cost increases incurred by the suppliers and market conditions. Our coal purchase obligations exclude any purchases we have with our subsidiaries.

Environmental Regulations and Litigation

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

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

Collom Air Permit On July 25, 2018, the Center for Biological Diversity and Sierra Club filed a complaint against the Colorado Department of Public Health and Environment, or the CDPHE, in opposition to CDPHE's issuance of an air permit for construction and operation of the Collom pit at the Colowyo Mine. On February 14, 2019, the court issued a stay of the case proceedings while CDPHE processed a permit revision. On November 7, 2019, the Collom air permit revision was issued by CDPHE. On December 11, 2019, the Center for Biological Diversity and Sierra Club filed a new case challenging the CDPHE's issuance of the Collom air permit revision. We filed a motion to intervene as an intervenor-defendant on January 28, 2020. On October 6, 2020, the oral arguments occurred. On October 21, 2020, the judge issued an order affirming the CDPHE's issuance of the minor source construction air permit to Collom. 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, 2019. Rating Triggers Our current senior secured ratings are "A3 (stable outlook)" by Moody's Investors Services, or Moody's, "A- (negative 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. Our Revolving Credit Agreement includes a pricing grid related to the LIBOR spread, commitment fee and letter of credit fees due under the facility. We also have a term loan agreement that includes a pricing grid related to the LIBOR spread. A downgrade of our senior secured ratings could result in an increase in each of these pricing components. We do not believe that any such increase would be significant or have a material adverse effect on our financial condition or our future results of operations. We currently have contracts that require adequate assurance of performance. These include natural gas supply contracts, coal purchase contracts, and financial risk management contracts. Some of the contracts are directly tied to our credit rating generally being maintained at or above investment grade by S&P and Moody's. We may enter into additional contracts which may contain similar adequate assurance requirements. If we are required to provide such adequate assurances, we do not believe the amounts will be significant or that they will have a material adverse effect on our financial condition or our future results of operations. 37

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Off Balance Sheet Arrangements

We have no off-balance sheet arrangements.

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