UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

OR

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to

Commission File No. 333-212006

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

(Exact name of registrant as specified in its charter)

(303) 452-6111

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:  NONE

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.  ☐ Yes  ☒ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  ☒ Yes    ☐ No

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ☐ Yes    ☐ No  (Note: The registrant is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), but voluntarily files reports with the Securities and Exchange Commission. The registrant has filed all Exchange Act reports for the preceding 12 months (or for such shorter period that the registrant was required to file such reports)).

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☒ Yes    ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☐  Accelerated Filer ☐    Non-accelerated Filer ☒ Smaller Reporting Company ☐ Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ☐ Yes  ☒ No

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant:  NONE.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock.  The registrant is a membership corporation and has no authorized or outstanding equity securities.

Documents incorporated by reference:  NONE.

TRI-STATE GENERATION AN D TRANSMISSION ASSOCIATION, INC.

Index to 2019 Annual Report on Form 10-K

GLOSSARY

The following abbreviations and acronyms used in this annual report on Form 10-K are defined below:

FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains “forward‑looking statements.”  All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction, operation, or closure of facilities (often, but not always, identified through the use of words or phrases such as “will likely result,” “is expected to,” “will continue,” “is anticipated,” “estimated,” “forecasted,” “projection,” “target” and “outlook”) are forward‑looking statements.

Although we believe that in making these forward‑looking statements our expectations are based on reasonable assumptions, any forward‑looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward‑looking statements.

PART I

ITEM 1.BUSINESS

OVERVIEW

Our Business

Tri-State Generation and Transmission Association, Inc. is a taxable wholesale electric power generation and transmission cooperative operating on a not‑for‑profit basis serving large portions of Colorado, Nebraska, New Mexico and Wyoming. We were incorporated under the laws of the State of Colorado in 1952 as a cooperative corporation. We supply wholesale electric power to our forty-three Members, which, in turn, supply retail electric power to residential, commercial, industrial and agricultural customers.

We are owned entirely by our forty-six members. Thirty-nine of our members are not‑for‑profit, electric distribution cooperative associations. Four members are public power districts, which are political subdivisions of the State of Nebraska. We also have three non-utility members. The retail service territories of our Members cover approximately 200,000 square miles and their customers include suburban and rural residences, farms and ranches, and large and small businesses and industries. Our Members serve approximately 624,000 retail electric meters. Our Members are the sole state certified providers of electric service to retail (residential and business) customers within their designated service territories.

We became regulated as a public utility under Part II of the 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.

Our principal executive offices are located at 1100 West 116th Avenue, Westminster, Colorado 80234. Our telephone number is (303) 452‑6111. Our website is www.tristate.coop. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available on our website as soon as reasonably practicable after the material is filed with the SEC. Information contained on our website is not incorporated by reference into and should not be considered to be part of this annual report.

Including our subsidiaries, as of December 31, 2019, we employed 1,467 people, of which 280 were subject to collective bargaining agreements. As of December 31, 2019, none of these collective bargaining agreements will expire within one year. We expect the number of employees to decrease materially by 2030 with the closure of certain of our generating facilities and a coal mine by 2030.

Cooperative Structure

A cooperative is a business entity owned by its members. As organizations acting on a not‑for‑profit basis, cooperatives provide or purchase property, products or services to their members on a cost effective basis, in part by eliminating the need to produce profits or a return on equity in excess of required margins. Cooperatives generally establish rates to recover their cost and to collect a portion of revenues in excess of expenses, which constitute margins. Margins not yet distributed to members in cash constitute patronage capital, a cooperative’s principal source of equity. Patronage capital is held for the account of the members without interest and returned when the board of directors deems it appropriate to do so. The timing and amount of any actual return of capital to the members depends on the financial goals of the cooperative, current and projected capital expenditures, and the cooperative’s loan and security agreements.

Electric distribution cooperatives form generation and transmission cooperatives, such as us, to acquire power supply resources, typically through the construction of facilities or the development of other power purchase arrangements, at a lower cost than if they were acquiring those resources alone.

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 Member flexibility, all with a goal to lower wholesale rates to

our Members. In January 2020, we announced the actions of our Responsible Energy Plan, which will advance our cleaner generation portfolio and programs to serve our Members. Some of the actions of the Responsible Energy Plan include:

Power Supply and Transmission

We supply and transmit our 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, or have tolling arrangements or long-term purchase contracts with respect to, various generating facilities. As of January 1, 2020, our diverse generation portfolio provides us with maximum available power of 4,317 MWs and is summarized in the table below:

In early 2019, we announced the execution of a 100 MW solar-based power purchase contract and a 104 MW wind-based power purchase contract. In January 2020, we announced the execution of another 200 MW wind-based power purchase contract and five solar-based power purchase contracts totaling 615 MWs. In January 2020, we also announced the early retirements of Craig Station by 2030 and Escalante Station by the end of 2020. See “— POWER SUPPLY RESOURCES” and “PROPERTIES” for a description of our long-term purchase contracts and our generating facilities, including retirements of our generating facilities.

After the retirement of Escalante Station and the addition of new renewable generating facilities, as of January 1, 2025, we anticipate our generation portfolio to be the following:

In addition to our diverse generation portfolio, as permitted by our wholesale electric service contracts with our Members, as of December 31, 2019, our Members own or control through long-term purchase power contracts approximately 123 MWs of operating distributed or renewable capacity that is used to deliver energy to our Members’ customers.

We transmit power to our Members through resources that we own, lease or have undivided percentage interests in, or by wheeling power across lines owned by other transmission providers. We have ownership or capacity interests in approximately 5,671 miles of high‑voltage transmission lines and own or have major equipment ownership in approximately 407 substations and switchyards. See “PROPERTIES” for a description of our transmission facilities.

MEMBERS

General

We have two classes of members - all requirements electric members known as our Members or Class A members and non-utility members. Our Members provide electric services, consisting of power supply and distribution services, to residential, commercial, industrial and agricultural customers primarily in Colorado, Nebraska, New Mexico and Wyoming. Our Members’ businesses involve the operation of substations, transformers and electric lines that deliver power to their customers. We currently have 43 Members. Our Members and their locations are as follows:

We also currently have 3 non-utility members. Our non-utility members are as follows: Ellgen Ranch Company, MIECO, Inc., and Olson’s Greenhouses of Colorado, LLC. Ellgen Ranch Company is located in Colorado and is a party to ranch leases with Colowyo Coal. MIECO, Inc. is a California-based company that markets natural gas nationwide and is a major supplier of gas to our natural gas-fired generating facilities. Olson’s Greenhouses of Colorado, LLC is headquartered in Utah and conducts business in Colorado. Olson’s Greenhouses of Colorado, LLC purchases thermal energy from us and reuses the waste steam that is generated from the J.M. Shafer Generating Station to heat its greenhouses.

Bylaws and Classes of Membership

Our Bylaws require each Member, unless otherwise specified in a written agreement, to purchase all electric power and energy used by the Member from us. This requirement in our Bylaws is further specified in the wholesale electric service contract with each Member, which is an all-requirements contract. Each wholesale electric service contract obligates us to sell and deliver to the Member, and obligates the Member to purchase and receive, at least 95 percent of its electric power requirements from us.    

At the 2019 annual meeting of our members, our members approved amendments to our Bylaws to allow our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership. In July 2019, our Board, in accordance with the amended Bylaws, established a non-utility membership class and authorized entering into membership agreements with non-utility members. The non-utility membership class, as set forth in the membership agreements with such non-utility members, have a right to vote at membership meetings, have rights to patronage capital, and have rights to liquidation proceeds, but have no representation on our Board.  We currently have 3 non-utility members. We may add new members in the future.

Pursuant to our Bylaws, a 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 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.  From time to time, a Member may request equitable terms and conditions as our Board may prescribe for withdrawal or we may provide for informational purposes to all or a portion of our Members equitable terms and conditions for withdrawal. In addition, from time to time, we may be in discussions with a Member regarding the equitable terms and conditions for withdrawal and their request for withdrawal, including granting a Member permission to explore options for potential alternative supplies of power known as shopping letters. However, any such permission is not considered authorization to withdraw and does not change the Member’s requirements and obligation to comply with such equitable terms and conditions as our Board may prescribe. A non-utility member’s ability to withdrawal from membership in us is as provided in their respective membership agreement.

Wholesale Electric Service Contracts

Our revenues are derived primarily from the sale of electric power to our Members pursuant to long‑term wholesale electric service contracts. We have entered into substantially similar contracts with each Member extending through 2050 for 42 Members (which constituted approximately 96.8 percent of our revenue from Member sales in 2019) and extending through 2040 for the remaining Member (DMEA).

The wholesale electric service contracts are subject to automatic extension thereafter until either party provides at least two years’ notice of its intent to terminate. Each contract obligates us to sell and deliver to the Member, and obligates the Member to purchase and receive from us, at least 95 percent of the power it requires for the operation of its system, except for sources, such as photovoltaic cells, fuel cells, or others that are not connected to such Member’s distribution or transmission system. Each Member may elect to provide up to 5 percent of its requirements from distributed or renewable generation owned or controlled by the Member. As of December 31, 2019, 21 Members have enrolled in this program with capacity totaling approximately 136 MWs of which 123 MWs are in operation. In 2019, we estimate that nearly a third of the energy delivered by us and our Members to our Members’ customers came from non-carbon emitting resources. See also “— MEMBERS – Contract Committee” for a description of our community solar program for our Members.

Our Members’ demand for energy is influenced by seasonal weather conditions. Historically, our peak load conditions have occurred during the months of June through August, which is when irrigation loads are the highest. Our summer peak load conditions depend on summer temperatures and the amount of precipitation during the growing season (generally May through September). Relatively higher summer or lower winter temperatures tend to increase the demand and usage of electricity for heating, air conditioning and irrigation. Mild weather generally reduces the demand and usage of electricity because heating, air conditioning and irrigation systems are operated less frequently.

The below table shows our Members’ aggregate coincident peak demand for the years 2015 through 2019 and the amount of energy that we supplied them. Our Members’ peak demand and our annual amount of energy sold to our Members for 2019 increased by 1.2 percent and 0.2 percent, respectively, compared to 2018.

Subject to certain force majeure conditions, we are required under the wholesale electric service contracts to use reasonable diligence to provide a constant and uninterrupted supply of electric service to our Members. If our generation and sources of supply are inadequate to serve all of our Members’ demand, and we are unable to secure additional sources of supply, we are permitted to interrupt service to our Members in accordance with a written policy established by our Board. We are currently able to provide all the requirements of our Members and intend to construct the necessary facilities or make other arrangements to continue to do so.

The wholesale electric service contracts we have with our Members provide that our Members shall pay us for electric service at rates and on the terms and conditions established by our Board at levels sufficient to produce revenues, together with revenues from all other sources, to meet our cost of operation, including reasonable reserves, debt and lease service, and development of our equity. See “— RATE REGULATION.”  Our Members are obligated to pay us monthly for the power, energy and transmission service we supply to them. Revenue from one Member, United Power, comprised 16.6 percent of our Member revenue and 14.8 percent of our operating revenue in 2019. No other Member exceeded 10 percent of our Member revenue or our operating revenue in 2019. Payments due to us under the wholesale electric service contracts are pledged and assigned to secure the obligations secured under our Master Indenture. A Member cannot resell at wholesale any of the electric energy delivered to it under the wholesale electric service contract, unless such resale is approved by our Board or provided for in a schedule to the wholesale electric service contract.

We and our Members are subject to regulations issued by FERC pursuant to PURPA with respect to matters involving the purchase of electricity from, and the sale of electricity to, qualifying facilities and co‑generators. In June 2015, FERC clarified that the 5 percent limitation in our wholesale electric service contracts with our Members related to distributed or renewable generation owned or controlled by our Members did not supersede PURPA and the requirement of our Members to purchase power from qualifying facilities. In February 2016, we filed a Petition for Declaratory Order with FERC for a clarification that the fixed cost recovery mechanism in our revised Board policy is consistent with the provisions of PURPA and the implementing regulations of FERC. The revised Board policy provides for recovery of the unrecovered fixed costs directly from that Member, rather than allocating the costs among all of our Members. The fixed cost recovery is calculated based on the difference between our wholesale rate to our Members and our avoided costs. In June 2016, FERC denied our Petition for Declaratory Order related to the fixed cost recovery mechanism in our revised Board policy. We filed a Request for Rehearing with FERC regarding FERC’s June 2016 order. We are awaiting FERC’s decision on our request for rehearing. See “LEGAL PROCEEDINGS.”

In July 2016, we filed on behalf of ourselves and thirty of our Members a petition for a partial waiver for FERC’s PURPA regulations. Pursuant to such petition, we will purchase capacity and energy from qualifying facilities that interconnect to distribution systems of those Members who are participating in the waiver program. We will make such purchase at a rate equal to our full avoided cost. As part of the waiver program, those participating Members will sell supplementary, back-up, and maintenance power to the qualifying facilities. We are awaiting FERC’s decision on this petition for waiver.

Contract Committee

The wholesale electric service contracts we have with our Members provides for us to establish a committee every 5 years to review the wholesale electric service contracts for the purposes of making recommendations to our Board concerning any suggested modifications. In 2016 and 2017, a contract committee consisting of a representative from each Member discussed changes to the wholesale electric service contracts. The contract committee in 2017 recommended to our Board no changes to the wholesale electric service contracts with our Members, but did recommend that the contract committee be reconvened in 2 years. In 2019, the contract committee consisting of a representative from each Member reconvened to review the wholesale electric service contracts and discuss changes, including alternative contracts with our Members.

The contract committee has regularly met since it convened in 2019 to discuss alternative contracts for our Members, including partial requirements contracts. As part of the contract committee considering alternative contracts with our Members, including partial requirements contracts, and the interaction with shopping letters and the withdrawal number for a Member to meet all its contractual obligations to us, at our September 2019 Board meeting, our Board approved a temporary suspension of the policy and practice of providing its Members with withdrawal numbers and shopping letters. The suspension is expected to continue until the contract committee has completed its work and provided recommendations to our Board, our Board has had an opportunity to consider and act upon such recommendations, and our Board has fully assessed the financial impacts of Member withdrawals and/or the offering of alternative contracts. At our September 2019 Board meeting, our Board also authorized the contract committee to consider alternative methods to determine the withdrawal number with a goal of completing such work and presenting it to our Board by April 2020.

In November 2019, the contract committee recommended to the Board and the Board approved a community solar garden program, which is in addition to the 5 percent self-supply provision of the wholesale electric service contracts. Each Member is eligible for community solar garden projects up to, in aggregate, the lesser of 4.6 million kWhs or 2 percent of such Member’s 2018 energy sales from us. The community solar garden program, if acted upon by all Members, would be approximately 63 MWs of community solar projects. In February 2020, the contract committee recommended to the Board and the Board announced a commitment to provide our Members with the option of entering into a partial requirements contract.  The partial requirements option is subject to further refinement, but is expected to include holding an open season for Members to choose to enter into a partial requirements contract and the open season would permit Members collectively to self-supply up to 300 MWs, approximately 10 percent of our Members’ peak demand. The 300 MWs is in addition to the 5 percent self-supply provision of the wholesale electric service contracts and the community solar garden program. In addition, additional open seasons could be offered in the future and Members that choose the partial requirements option will make other Members financially whole through a buy-down payment or payments. The Board further directed the contract committee to make recommendations to the Board on the specific details for the partial requirements contracts, including the partial requirements buy-down number methodology and the process for implementing the offering.

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 Member flexibility,  all with a goal to lower wholesale rates to our Members. A key part of our approach was an engagement with former Colorado Governor Bill Ritter and the Center for the New Energy Economy at the Colorado State University to facilitate a collaborative stakeholder process for us that contributed to and helped define the Responsible Energy Plan.

In January 2020, we announced our Responsible Energy Plan, which will rapidly advance our transition to a cleaner generation portfolio and offer new programs to serve our Members. The plan, which was developed with input from our Board, our Members and external stakeholders, includes the following elements:

When we announced the Responsible Energy Plan, we also identified several challenges we need to work with others to address to ensure a cost-effective, efficient and equitable transition, including:

Members’ Service Territories and Customers

Service Territories. Our Members’ service territories are diverse, covering large portions of Colorado, Nebraska, New Mexico and Wyoming and very small portions of Arizona, Montana, and Utah. In accordance with state regulations, our Members have exclusive rights to provide electric service to retail customers within designated service territories. In Colorado, our Members’ service territories extend throughout the state and encompass suburban, rural, industrial, agricultural and mining areas. In Nebraska, our Members’ service territories are comprised primarily of rural residential and farm customers in the western part of the state. In New Mexico, our Members’ service territories extend throughout the northern, southern, central and western parts of the state, serving agricultural, rural residential, suburban, small commercial and mining customers. In Wyoming, our Members’ service territories extend from the north central to the southeastern part of the state and encompass rural residential, agricultural and mining areas. The differences in customer bases, economic sectors, climates and weather patterns of our Members’ service territories creates diversity within our system.

Customers.  According to information we received from our Members, our Members’ sales of energy in 2018 (which is the most recent information available to us) were divided by customer class as follows:

From 2014 to 2018, our Members experienced an average annual compound growth rate of approximately 1.4 percent in the number of customers and an average annual compound growth rate of 2.3 percent in energy sales. In 2018, which is the most recent year with data available to us, the 15 largest customers of our Members represented 17.4 percent of electric energy sales by our Members, although no single customer of our Members represented more than 4 percent of our total energy sales. These customers are primarily in the business of mineral extraction, natural gas, CO_2, oil production, or transportation of these.

Our Members’ average number of customers per mile of energized line is approximately five customers per mile. System densities of our Members in 2018 ranged from 1.2 customers per mile to 13.9 customers per mile.

Relationship with Members

We are a cooperative corporation, and our members are not our subsidiaries. We have no legal interest in, or obligation with respect to, any of the assets, liabilities, equity, revenue or margins of our members except with respect to the obligations of our members under their respective agreements with us. We have no control over or the right, ability or authority to control the electric facilities, operations, or maintenance practices of our Members. Pursuant to our Bylaws, we and our members disclaim any intent or agreement to be a partnership, joint venture, single or joint enterprise, or any other business form, except that of a cooperative corporation and member. The revenues of our members are not pledged to us.

Pursuant to our Bylaws, a 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 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.

DMEA requested an exit cost calculation from us and we provided to DMEA a preliminary buyout number. DMEA disputed the buyout number provided to DMEA by us and filed a formal complaint with the COPUC in December 2018 alleging that the COPUC had jurisdiction over the equitable terms and conditions as our Board may prescribe for withdrawal. In July 2019, we reached a settlement with DMEA that provides for their withdrawal from membership in us as permitted by our Bylaws, the resolution of all litigation with DMEA regarding various matters, the transfer of certain transmission assets to DMEA, the forfeiture by DMEA of the current balance of DMEA’s patronage capital allocation, and the payment to us of a withdrawal payment. The amount of the withdrawal payment was the product of the negotiated settlement with DMEA and is unique to DMEA because of the amounts associated with the transmission assets being transferred and patronage capital, and the date of withdrawal of DMEA from us. The specific terms of the settlement will be set forth in a withdrawal agreement, which will be subject to receipt of certain approvals and other conditions. The settlement agreement provides for the parties to cooperate to complete DMEA’s withdrawal effective May 1, 2020, but we expect the withdrawal effective date to occur at a later date agreed to by the parties.

In November 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 Members with withdrawal numbers is unlawful. LPEA seeks for the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the withdrawal number.  In November 2019, United Power 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 member under a partial requirements contract. United Power alleges,

among other things, that we have failed to provide a just, reasonable, and non-discriminatory withdrawal number. United Power seeks for the COPUC to issue an order establishing a withdrawal number. The COPUC has consolidated the proceeding. A five-day evidentiary hearing is scheduled to begin on March 23, 2020. See “LEGAL PROCEEDINGS.”

Eastern and Western Interconnection

North America is comprised of three major power grids, including the Western Interconnection and the Eastern Interconnection. The Western and Eastern Interconnection operate almost independently of each other with multiple direct current ties between the two grids. We have transmission facilities and serve our Members’ load in both the Western and Eastern Interconnection. Approximately 3.6 percent of our total load and transmission facilities are located in the Eastern Interconnection. Our generating facilities are located in the Western Interconnection and generally isolated from our Members’ load in the Eastern Interconnection. We purchase, under a long-term purchase contract with Basin, all the power which we require to serve our Members’ load in the Eastern Interconnection. See “— POWER SUPPLY RESOURCES — Purchased Power.”

Competition

In accordance with state regulations, our Members have exclusive rights to provide electric service to retail customers within designated service territories. States in which our Members’ service territories are located have not enacted retail competition legislation. Federal legislation could mandate retail choice in every state. Our Members are subject to customer conservation and energy efficiency activities, as well as initiatives to utilize alternative energy sources, including self-generation, or otherwise bypass our Members’ systems. Our Members are also subject to competition for attracting new loads as potential customers may locate their facilities in our Member’s designated service territory or the service territory of a neighboring utility.

In 1992, we entered into an agreement expiring in December 2025 with PSCO and PacifiCorp, two of the principal investor‑owned utilities adjacent to our Members’ service territories in Wyoming and Colorado that provides, among other things, that each of PSCO, PacifiCorp and us will:

We and our Members are subject to competition from third party energy remarketing companies. Energy remarketing companies are targeting our Members and the communities our Members serve by claiming to be able to offer lower priced and cleaner wholesale electric power. This includes assisting our Members in seeking to withdrawal from membership in us and financing the withdrawal number payable by our Members. It also includes assisting some municipalities that our Members serve by helping them create electric utilities.

RATE REGULATION

New Developments

At our July 2019 Board meeting, because of increased pressure by the states to regulate our rates and charges, our Board authorized us to take action to place us under wholesale rate regulation by FERC. In connection with such authorization, our Board, in accordance with our Bylaws, established a non-utility membership class and authorized entering into membership agreements with non-utility members.  On July 23, 2019, we filed with FERC our initial tariff, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. Our FERC tariff filing included our current Class A rate schedule (A-40) for electric power sales to our Members as the wholesale rates payable by our Members.  Numerous parties filed interventions or protests with FERC.

On September 3, 2019, a membership agreement with a non-utility member, MIECO, Inc., became effective and we notified FERC of such and requested a partial waiver.  The admission of the new 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 FPA.  On October 4, 2019, FERC issued an order rejecting our filings without prejudice to us submitting a more complete set of filings that cure the deficiencies set forth in such order. The FERC order did not rule on any of the substantive issues raised by those that filed interventions or protests.

During the week of December 23, 2019, we filed our revised set of filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. Numerous parties filed interventions or protests with FERC. We expect FERC to rule on their acceptance of these tariffs by the end of March 2020. See “LEGAL PROCEEDINGS.”

General

The electric power we provide to our Members continues to be at rates established by our Board, but such rates are now subject to FERC’s approval. Our wholesale electric service contracts with our Members provide that rates paid by our Members for the electric power we supply to them must be set at levels sufficient to produce revenues, together with revenues from all other sources, to meet our cost of operation, including reasonable reserves, debt and lease service, and development of equity. We provide electric power to non‑members at contractual rates under long‑term arrangements and at market prices in short-term transactions, subject to FERC market based rate authority.

Our electric sales revenues are derived from electric power sales to our Members and non‑member purchasers. Revenues from electric power sales to our Members are primarily from our Class A wholesale rate schedule. Our Class A rate schedule for electric power sales to our Members consist of three billing components: an energy rate and two demand rates. 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 Members. Energy is the physical electricity delivered to our Members. In 2019 (A‑40 rate), 2018 (A‑40 rate), and 2017 (A‑40 rate), our Class A wholesale rate schedules used the same rate design. 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 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. This rate structure was filed at FERC as a “stated rate” where we requested FERC to approve the existing rate as stated. However, upon our next rate change, we will be required to justify the new rate at FERC with a rate case, likely to be contested. While our Board still has authority in determining our proper rates, those rates must be further approved by FERC subject to outside comments.

Approved by our Board in September 2019, the A‑40 rate schedule will continue in effect for 2020 and that rate was filed at FERC on December 23, 2019 for acceptance by the end of March 2020.

Rate Policy

Under the Master Indenture, we are required to establish rates annually that are reasonably expected to achieve a DSR of at least 1.10 on an annual basis and requires us to maintain an ECR of at least 18 percent at the end of each fiscal year. Our Board has adopted and periodically reviews and revises a Board Policy for Financial Goals and Capital Credits, which currently targets rates payable by our Members to produce financial results above the requirements of our Master Indenture. Our management proposes rates that are expected to adequately recover our annual Member revenue requirements contingent upon load projections and a budget approved annually by our Board. Our Board reviews the budget and our underlying rates on an annual basis in accordance with our financial goals and rate objectives, and in accordance with the financial covenants contained in our debt instruments. The Master Indenture also requires that we review rates promptly at any point during the year upon any material change in circumstances which was not contemplated during the annual review of Member rates. Any rate changes going forward will be filed at FERC for their acceptance. 

The following table shows our average Member revenue/kWh for the years 2015 through 2019. The average Member revenue/kWh is our total Members’ electric sales revenue in a given year divided by the total kilowatt hours

sold to our Members in that given year. The average Member revenue/kWh does not represent the actual energy and demand rate components established by our Board and paid by our Members for the years 2015 through 2019.

Regulation of Rates

Our rates are established by our Board. However, we were required to file our Member rates with the NMPRC and, according to New Mexico law, the NMPRC had regulatory authority over our rates in New Mexico in the event three or more of our New Mexico Members filed a request to review our rates and the NMPRC found such request to be qualified. See “LEGAL PROCEEDINGS.” However, now that our rates are FERC jurisdictional, we no longer have an obligation to file rates in New Mexico.

Under the FPA, an electric cooperative is not subject to rate regulation by FERC, if it is financed by the United States Department of Agriculture, Rural Utilities Service or it sells less than 4 million MWhs of electricity per year; or it is wholly owned, directly or indirectly, by any one or more of the foregoing. While each of our Members sells fewer than 4 million MWhs per year, the addition of non-cooperative members in 2019 and specifically the addition of MIECO, Inc. on September 3, 2019 removed the exemption from FERC regulation for us, thus subjecting us to full rate and transmission jurisdiction by FERC on September 3, 2019. Full rate regulation includes FERC reviewing our rates upon its own initiative or upon complaint and ordering a reduction of any rates determined to be unjust, unreasonable, or otherwise unlawful and ordering a refund for amounts collected during such proceedings in excess of the just, reasonable, and lawful rates.

In addition to its jurisdiction over rates, FERC also regulates the issuance of securities and assumption of liabilities by us, as well as mergers, consolidations, the acquisitions of securities of other utilities, and the disposition of property subject to FERC jurisdiction. Under FERC regulations, we are prohibited from selling, leasing, or otherwise disposing of the whole of our facilities subject to FERC jurisdiction, or any part of such facilities having a value in excess of $10 million without having FERC approval. We are also required to seek FERC approval prior to merging or consolidating our facilities with those of any other entity having a value in excess of $10 million.

POWER SUPPLY RESOURCES

We provide electric power to our Members through a combination of generating facilities that we own, contract for, lease, have undivided percentage interests in or have tolling arrangements with, and through the purchase of electric power pursuant to power purchase contracts and purchases on the open market.

In 2019, 61.5 percent of our energy available for sale was provided by our generation and 38.5 percent by purchased power. We expect the amount of energy we purchase to increase in the future with the closures of our coal-fired base load facilities and the increasing amount of renewable power purchase contracts. In 2019, we estimate that nearly a third of the energy delivered by us and our Members to our Member’s customers came from non-carbon emitting resources. We estimate that 50 percent of the energy delivered by us and our Members to our Member’s customers will come from renewable resources by 2024.

Depending on our system requirements and contractual obligations, we are likely to both purchase and sell electric power during the same fiscal period. We use market transactions to optimize our position by routinely purchasing power when the market price is lower than our incremental production cost and routinely selling power to the short-term market when we have excess power available above our firm commitments to both Members and non-members. We also use short-term market purchases during periods of generation outages at our facilities.

Generating Facilities

We own, lease, have undivided percentage interests in, or have tolling arrangements with respect to 1,782 MWs from coal‑fired base load facilities and 903 MWs from gas/oil‑fired facilities. See “PROPERTIES” for a description of our various generating facilities.

On September 19, 2019, our 100 MW Nucla Generating Station was officially retired from service. Nucla Generating Station, which had been in a ready-to-run status, was to be retired by the end of 2022 as required by Colorado’s State Implementation Plan.

On December 31, 2019, our gas tolling arrangement with AltaGas Brush Energy Inc. to provide intermediate load generating capacity of 70 MWs from a combined-cycle facility located near Brush, Colorado expired.

On September 1, 2016, we announced that the owners of Craig Station Unit 1 intend to retire Craig Station Unit 1 by December 31, 2025, which includes our 102 MW share from such unit. On January 9, 2020, we announced that our Board approved the early retirement of Craig Station Units 2 and 3. Our share of Craig Station Unit 2 is 98 MWs. We are working with the other joint owners of Craig Station Unit 2 to determine the specific details for the retirement of Craig Station Unit 2. We own and operate the 448 MW Craig Station Unit 3. The early retirement of Craig Station is expected to impact approximately 253 employees.

On January 9, 2020, we also announced that our Board approved the early retirement of our 253 MW Escalante Station by the end of 2020. The early retirement of Escalante Station is expected to impact approximately 107 employees.

After the planned retirements of Craig Station and Escalante Station, our interest in coal-fired base load facilities is expected to decrease to 881 MWs, which is expected to be a decrease of over 50 percent compared to our 1,874 MWs of coal-fired base load interest in 2015.

Purchased Power

We supplement our capacity and energy requirements not supplied by our generating facilities through long‑term purchase contracts and short‑term energy purchases. Our largest long‑term power purchase contracts are discussed below.

Basin. In 2017, we entered into two new amended and restated wholesale power contracts with Basin. The new wholesale power contracts amended and restated a 1975 wholesale power contract with Basin and separated the prior 1975 wholesale power contract into two wholesale power contracts: one for the Western Interconnection and one for the Eastern Interconnection.

The wholesale power contract for the Eastern Interconnection provides the terms under which we purchase in the Eastern Interconnection all the power which we require to serve our Members’ load in the Eastern Interconnection. The Members’ peak load in the Eastern Interconnection in 2019 was approximately 305 MWs.

The wholesale power contract for the Western Interconnection provides the terms under which we purchase in the Western Interconnection fixed scheduled quantities of electric power and energy. The quantity of electric power and energy varies depending on the month and hour with a maximum of 268 MWs occurring during certain hours in July.

Both amended and restated wholesale power contracts continue through December 31, 2050 and are subject to automatic extension thereafter until either party provides at least five years’ notice of its intent to terminate.

Renewables.  Our principal long-term renewable power purchase contracts are with WAPA. Substantially all of our purchases from WAPA are hydroelectric based power made at cost‑based rates under long‑standing federal law under which WAPA sells power to cooperatives, municipal electric systems and certain other “preference” customers. WAPA markets and transmits the power to us pursuant to five contracts, two contracts relating to WAPA’s Loveland

Area Projects (one which terminates September 30, 2024 and one which commences delivery on October 1, 2024 and terminates September 30, 2054) and three contracts relating to WAPA’s Salt Lake City Area Integrated Projects (two which terminate September 30, 2024 and one which commences delivery on October 1, 2024 and terminates September 30, 2057). The amount of long-term power delivery from WAPA under the two contracts that begin delivery of power on October 1, 2024 is anticipated to remain near the current amount under the existing three contracts terminating on September 30, 2024. The Loveland Area Projects generally consist of generation and transmission facilities located in the Missouri River Basin. The Salt Lake City Area Integrated Projects generally consist of generation and transmission facilities located in the Colorado River Basin. The following table shows the long-term power delivery from WAPA in the summer season (April-September) and winter season (October‑March):

In addition to our contracts with WAPA for hydroelectric power purchases, we have entered into renewable power purchase contracts to purchase the entire output from specified renewable facilities totaling approximately 1498 MWs, including 671 MWs of wind-based power purchase contracts and 800 MWs of solar-based power purchase contracts. The largest of these renewable power purchase contracts are summarized in the table below. A majority of these renewable power purchase contracts below include the option for us to purchase the renewable facility at certain points during the term of the power purchase contract.

Other.  In 2016, we entered into a five year reciprocal contract with PNM to sell PNM 100 MWs of power, contingent on the operation of Springerville Unit 3, and purchase from PNM 100 MWs of power, contingent on the operation of PNM’s San Juan Generating Station Unit 4. After the initial five year period, the contract automatically

renews for successive one year terms until terminated by either party. This contract with PNM reduces our amount of needed operating reserves and reduces the amount of power we would need to purchase in the event of a forced outage of Springerville Unit 3. The net of the sales revenue and purchased power costs under this contract is included in purchased power expense on our consolidated statements of operations.

In addition to long‑term power purchase contracts, we utilize market purchases to optimize our position by routinely purchasing power when the market price is lower than our incremental production cost. We also utilize short-term market purchases during periods of generation outages. In addition, we have hazard sharing arrangements with Platte River Power Authority and TEP, which provide for supply of power to us in the event of forced outages at specified generating facilities.

Power Sale Contracts

We have various long-term power sales contracts with other entities totaling approximately 225 MWs, the largest of which are discussed below. We have a contract to sell Salt River Project 100 MWs of power, contingent on the operation of Springerville Unit 3, which expires in August 2036. We also have a five-year reciprocal contract to sell PNM 100 MWs of power, contingent on the operation of Springerville Unit 3. See “— POWER SUPPLY RESOURCES – Purchased Power.” We, through one of our wholly owned subsidiaries, had a contract that expired in June 2019 to sell PSCO 122 MWs in tolling capacity from the J.M. Shafer Generating Station.

In addition to long‑term power sales contracts, we routinely sell power to the short‑term market when we have excess power available above our firm commitments to both Members and non‑members.

We are subject to varying degrees of competition related to the sale of excess power to non-members on both a short-term and long-term basis. We are subject to competition from regional utilities and merchant power suppliers with similar opportunities to generate and sell energy at market-based prices and larger trading entities that do not own or operate generating assets.

Energy Imbalance Markets

In September 2019, we announced, together with Basin, WAPA Rocky Mountain Region, WAPA Upper Great Plains West, and WAPA CRSP, our decision to join SPP’s Western Energy Imbalance Service market. Since then Municipal Energy Association of Nebraska and Wyoming Municipal Power Agency have also joined. SPP is expected to launch the Western Energy Imbalance Service market in February 2021. The market will centrally dispatch energy from these participants through the region every five minutes, and is expected to enhance both the reliability and affordability of electricity delivered from utilities to their customers. It will also help facilitate the integration of additional renewable resources within the region.

In April 2021, PNM plans to join as an EIM entity in the CAISO Western Energy Imbalance Market. This will affect our loads and resources within the PNM balancing authority, which is all our loads and resources in New Mexico. We plan to register as a CAISO scheduling coordinator, and register our New Mexico resources and Springerville Unit 3 generation as participating resources with the CAISO, in order for our generation to participate in this imbalance market. We have had member load in the CAISO Western Energy Imbalance Market since it began in 2015 with our small amount of load in the PacifiCorp balancing authority.

In addition, we continue to explore options to participate in a regional transmission organization in the Western Interconnection. We believe a Western Interconnection regional transmission organization is necessary to achieve the full benefits of organized markets and to meet future state carbon goals.

Fuel Supply

Coal.  We purchase coal under long‑term contracts. See “PROPERTIES” for a description of our investments in coal mines. The following table summarizes the sources of our coal for each of our coal‑fired generating facilities:

Colowyo Mine: As current mining operations in the South Taylor pit are being completed and land is being reclaimed, Colowyo Coal, a subsidiary of ours, is developing the Collom pit at the Colowyo Mine to access coal reserves for future production. In January 2017, Colowyo Coal received final approval of the mining plan from OSMRE. In October 2018, Colowyo Coal received a renewal of a water/wastewater discharge permit, which now also includes the Collom pit. In November 2019, CDPHE issued an air permit revision for the construction and operation of the Collom pit. Coal production from the Collom pit began in July 2019. See “— ENVIRONMENTAL REGULATIONS – Other Environmental Matters.”

Reclamation Liabilities.    In connection with our use of coal derived from coal mining facilities in which we have an ownership interest, including the Colowyo Mine, New Horizon Mine, Trapper Mine, Dry Fork Mine, and Fort Union Mine, there are certain reclamation activities mandated by state and federal laws. These liabilities are recognized and recorded on our financial statements when required by accounting guidelines. In 2019, we provided guarantees of, or performance bonds for, certain reclamation obligations of WFW and our subsidiaries. The amount of these performance bonds or guarantees are based upon applicable state requirements and are different than the amount of liabilities recognized on our financial statements in accordance with GAAP. We do not expect any changes in regulations that would reduce the amount we may guarantee of the reclamation obligations of WFW or our subsidiaries to have a material impact on us.

Natural Gas.  The majority of the natural gas we purchase is for facilities used primarily to fill peak demands. We currently purchase the majority of our gas supplies on the spot market at fixed daily prices and on occasion we enter into forward fixed‑price, fixed‑quantity physical contracts. The majority of natural gas is purchased in the Cheyenne Hub area, which is in close proximity to the natural gas generating facilities we tend to utilize most frequently. This includes purchases from our member, MIECO, Inc. Six major natural gas pipelines have interconnections at the Cheyenne Hub, and presently, there is adequate supply at this location. Based on the regional forecast of production activities and pipeline capacity in the Rocky Mountain region, we presently anticipate that sufficient supplies of natural gas will be available in the foreseeable future. We have a long‑term natural gas transportation contract that provides firm rights to move natural gas from various receipt points to our facilities. Finally, we may utilize financial instruments to price hedge our forecasted natural gas requirements.

Oil.  Distillate fuel for the Burlington, Limon, Knutson and Pyramid Generating Stations, all simple-cycle combustion turbine facilities, is purchased on the spot market from various suppliers. Oil is transported to the respective locations via truck.

Water Supply

We use varying amounts of water for the production of steam used to drive turbines that turn generators and produce electricity in our generating facilities.

We maintain a water portfolio that supplies water from various sources for each of our generating facilities. This portfolio is adequate to meet the water supply requirements of our generating facilities. Our generating facilities are located in the western part of the United States where demand for available water supplies is heavy, particularly in drought conditions. Litigation and disputes over water supplies are common and sometimes protracted, which can lead to uncertainty regarding any user’s rights to available water supplies. If we become subject to adverse determinations in water rights litigation or to persistent drought conditions, we could be forced to acquire additional water supplies or to curtail generation at our facilities.

We are involved in a proceeding in the State of New Mexico that could impact the water rights for Escalante Station. It is an adjudication of water rights associated with the Bluewater Toltec Area to determine the past, present and future use of water rights of the Pueblos of Acoma and Laguna, which we collectively refer to as the Pueblos. Specifically, the Pueblos are seeking a determination of the volume of ground water and surface water available to them and to determine the priority of those water rights. Should the Pueblos prevail in court, permitted water rights available for the Escalante Station will be significantly reduced, potentially requiring us to secure alternative water supplies at a cost which could potentially be higher than the cost of the water supplies currently being used.

We were also involved in a proceeding in the State of Colorado related to the water rights of Burlington Generating Station and that matter was dismissed without adverse impact to our water rights.

Resource Planning

We continually evaluate potential resources required to serve the long‑term requirements of our Members. As part of our approach to resource planning, we evaluate various resource options including the construction of new resources and long-term power purchase contracts. In evaluating future renewable portfolio additions, we monitor market conditions, tax credit expiration schedules, impacts of current renewable resources on reliable system operations and the operation of existing generation assets, transmission system capacity, our potential participation in an organized market in the Western Interconnection, and the regulatory requirements for meeting RPS and other similar state laws and goals regarding reductions in CO₂ emissions. Consistent with this strategy, our most recent request for proposal issued in June 2019 and subsequent award of power purchase contracts for 200 MWs of wind and 615 MWs of solar allowed us to add cost effective resources to our power supply portfolio. Based upon our current Member load/resource balance forecast, we do not anticipate a near term need for additional capacity.

The Colorado General Assembly in 2019 passed legislation that revises processes undertaken by the COPUC. Senate Bill 19-236, Sunset Public Utilities Commission, which was signed by the Colorado Governor on May 30, 2019, continues the COPUC for seven years. Among other provisions, the bill requires us to file and obtain COPUC approval for integrated or electric resource plans and directs the COPUC to require electric public utilities to consider the cost of CO₂ emissions in certain proceedings. On July 31, 2019, the COPUC opened a rulemaking pursuant to Senate Bill 19-236 proposing electric resource planning rules applicable to us. We, along with two Members and others, filed initial comments on September 11, 2019. We, along with others, also filed reply comments on September 25, 2019. The COPUC held an en banc hearing on the proposed rule on October 15, 2019 and subsequently held deliberations on the matter at its regular weekly public meeting on January 22, 2020. While a final commission decision is still pending, the COPUC did affirm a similar “Phase I/Phase II” electric resource planning process to us as it currently applies to Colorado’s investor owned utilities. We are expecting to file an initial assessment of existing resources by June 1, 2020 with an application for approval of the full plan due by December 1, 2020. The bill and final rules could have a material impact on our operations and our future generation portfolio; however, until the final rules are enacted that implement the bill, it is not yet possible to estimate the impacts on our operations or future generation portfolio.

As part of our long-term resource planning, we have acquired real estate interests and water rights for a project called the Colorado Power Project located near Holly, Colorado. Through December 2019, we have incurred

development costs of approximately $75.2 million, which is primarily the cost for the purchase of certain water rights and real estate interests, in connection with the Colorado Power Project. We have not yet selected a fuel or generation technology for this development, and we have not applied for an air permit for this development.

Over the past decade, in a joint effort with Sunflower, a Kansas generation and transmission cooperative, and others, we had pursued development of approximately 895 MWs of coal‑fired base load generating capacity to be located near Holcomb, Kansas, at the site of the existing Holcomb Generating Station. During the second quarter of 2017, we determined the probability of us entering into construction for the project was remote.  In January 2020, our Board officially canceled the Holcomb expansion project and committed to not develop additional coal-fired generating facilities.

TRANSMISSION

We have ownership or capacity interests in approximately 5,671 miles of high‑voltage transmission lines and own or have major equipment ownership in approximately 407 substations and switchyards. See “PROPERTIES” for a description of our transmission facilities.

Our system is interconnected with those of other utilities, including WAPA, NPPD, Black Hills Colorado Electric, Inc., PacifiCorp, PSCO, Platte River Power Authority, Colorado Springs Utilities, Basin, TEP, PNM and Deseret Generation & Transmission Cooperative. The majority of our transmission facilities operate as part of the Western Interconnection. The Western Interconnection consists of transmission assets that link generating facilities to load centers throughout the region. A small portion of our facilities support our load centers in the Eastern Interconnection. We continue to make the capital investment necessary to expand our transmission infrastructure and participate in many joint projects with other transmission owners to provide electric service to our Members.

The FPA authorizes FERC to oversee the sale at wholesale and transmission of electricity in interstate commerce by public utilities, as that term is defined in the FPA. Prior to September 3, 2019, we were not subject to the general “public utility” regulation of FERC under the FPA because of the exempt status of our Members.  The addition of non-cooperative members in 2019 and specifically, the addition of MIECO, Inc. on September 3, 2019 removed this exemption.  Thus, we are now subject to the general “public utility” regulation of FERC under the FPA and are now fully under FERC jurisdiction for rates and transmission service.  We filed our electric tariff including the OATT in stages during the week of December 23, 2019 and we expect FERC to rule on the acceptance of those tariffs by the end of March 2020. See “LEGAL PROCEEDINGS.” However, we have been operating under the FERC pro forma OATT since September 3, 2019. FERC requires both public utilities and non‑public utilities to comply with several requirements, including the requirements to provide open access transmission service and engage in regional planning of transmission facilities. We are also subject to reporting obligations applicable to all electric utilities, other FERC orders, and FERC’s oversight with respect to transmission planning, investment and siting, reliability standards, price transparency, and market manipulation. We are subject to regulations issued by FERC pursuant to the Energy Policy Act of 1992 and the Energy Policy Act of 2005 with respect to the provision of certain transmission services. 

We are a “transmission-owning member” of SPP, a regional transmission organization, for our transmission facilities and loads that are located in the Eastern Interconnection and constitute about 3.6 percent of our total loads and transmission facilities. On October 30, 2015, SPP filed revisions to its OATT to add an annual transmission revenue requirement and to implement a formula rate template and implementation protocols for those Eastern Interconnection transmission facilities on behalf of us for transmission service beginning January 1, 2016. NPPD filed motions protesting the October 2015 filing. On December 30, 2015, FERC issued an order accepting the formula rate subject to refund and setting it for settlement and hearing judge procedures. The settlement and hearing commenced in 2016 and involved two parts. The first part being the formula rate determinations, which was settled, and the second part being SPP’s zonal placement of our transmission facilities that are located in the Eastern Interconnection, which could not be settled and a hearing took place in November 2016. On February 23, 2017, the Administrative Law Judge issued an initial decision recommending that FERC approve SPP’s zonal placement of our transmission facilities on the zonal placement part. On May 17, 2018, FERC affirmed the initial decision and no refund was owed by us on this part of the matter.  On June 15, 2018, NPPD filed with FERC a request seeking rehearing of FERC’s May 17, 2018 order. On January 15, 2019, FERC denied NPPD’s request for rehearing. On March 15, 2019, NPPD filed a petition for review at the United States Court of

Appeals for the Eighth Circuit. On January 15, 2020, oral arguments related to NPPD’s petition took place before the Eighth Circuit.

On August 21, 2018, NPPD filed with FERC a complaint against us and SPP pursuant to Sections 206 and 306 of the FPA requesting FERC to find the inclusion of certain of our costs in our annual transmission revenue requirement causes SPP’s OATT to be unjust and unreasonable. On September 17, 2018, SPP filed a motion to dismiss and alternative answer and we filed an answer requesting that FERC deny NPPD’s complaint. On December 20, 2018, FERC issued an order denying the complaint. On January 18, 2019, NPPD filed with FERC a request seeking rehearing of FERC’s December 20, 2018 order. On September 19, 2019, FERC denied NPPD’s request for rehearing and dismissed the protest.

Open Access Transmission Service

Use of our transmission facilities is governed by OATTs. This arrangement flows from Order Nos. 888, 890, and 1000, which FERC issued in 1996, 2007 and 2011, respectively, as a means of promoting universal, non‑discriminatory and “open” access to the nation’s transmission grid. Open access generally gives all potential users of the transmission grid an equal opportunity to obtain the transmission service necessary to support purchases or sales of electric energy, thereby promoting competition in wholesale energy markets. In these orders, FERC generally required all transmission‑owning public utilities to provide transmission service on an open access basis. Since 2001, we have offered transmission service under an OATT for service across our system on a non‑discriminatory basis to satisfy the requirements of a non-public utility as defined by FERC. Beginning January 1, 2016, use of our Eastern Interconnection transmission facilities is governed by the SPP OATT and our costs of providing transmission service in the Eastern Interconnection are subject to review by FERC. Beginning September 3, 2019, we became fully FERC jurisdictional and began operating our Western Interconnection transmission facilities under the FERC pro forma OATT.  During the week of December 23, 2019, we filed our entire electric tariff including the conforming OATT at FERC and we expect FERC to rule on the acceptance of this filing by the end of March 2020.

When we were a non‑public utility, we were not required to implement the FERC Standards of Conduct which require separation between transmission operations and merchant operations (other than in connection with the reciprocity requirement described above). To ensure our compliance with the reciprocity requirement and contractual obligations relating to confidentiality and non‑disclosure of protected transmission information, we implemented FERC’s Standards of Conduct procedures in 2001, including procedures for transmission data confidentiality, by creating a physical and functional separation of protected transmission data from our employees and agents engaged in merchant functions. Now that we are fully FERC jurisdictional, we are required to implement the FERC Standards of Conduct.  Since our program has fully complied with FERC since 2001, no changes were required.

FERC has additional oversight authority over us under Sections 210 and 211 of the FPA, which apply to all transmitting utilities. Under these sections, FERC may, upon application by a customer, compel a utility to provide interconnection and transmission service to that customer, subject to appropriate compensation. We have not been the subject of an order under these provisions of the FPA.

Transmission Planning

FERC has become increasingly involved in promoting the development of the transmission grid. Prior to the 1990’s, most grid expansion planning was undertaken on a local basis, as utilities and, if applicable, state regulators determined which investments were appropriate to serve local customers. In Order No. 888, FERC encouraged utilities to coordinate their planning efforts with the expectation that integrated planning would better accommodate the development of regional, wholesale energy markets. In Order No. 890, FERC expressly required coordinated transmission planning, established governing principles, and cautioned that if non‑public utilities did not participate in coordinated transmission planning, FERC may compel them to do so. We comply with this requirement through our participation in WECC, WestConnect, SPP, and other sub‑regional transmission planning groups and processes. In Order No. 1000, FERC required all public utilities to engage in regional and interregional transmission planning and cost allocation. As it did with respect to open access transmission service, FERC stated that it may take action under Section 211A with respect to non‑public utilities that do not comply with the requirements of Order No. 1000; however,

FERC provides deference to non‑public utilities to encourage their participation, in particular by not requiring non‑public utilities to accept mandatory cost allocation. We voluntarily complied, while we were a non‑public utility, with Order No. 1000 by participating in regional and interregional transmission planning and cost allocation processes in SPP and WestConnect. However, beginning September 3, 2019, we became fully FERC jurisdictional and are required as a public utility to participate in regional transmission planning.  We notified the WestConnect participants of our change of status.  In conjunction with other utilities in the surrounding geographic area, we participate in WestConnect, a voluntary organization of transmission providers committed to assessing stakeholder needs in the Southwest. The participants in WestConnect own and operate transmission systems in all or part of the states of Arizona, New Mexico, Colorado, Wyoming, Nevada, and California.

FERC has also provided for rate incentives for public utilities as a means of encouraging investment in new transmission facilities. Recent approvals by FERC of rate incentives for transmission projects in our region and elsewhere have provided us with practical guidance as to the applicability of these incentives to potential future transmission projects.

Reliability

Section 215 of the FPA authorizes FERC to oversee the reliable operation of the nation’s interconnected bulk power system. In 2007, FERC approved mandatory national reliability standards for administration by NERC. The national standards apply to all utilities that own, operate, and/or use generating or transmission facilities as part of the interconnected bulk power system. As an owner, operator and user of generation and transmission facilities, we are subject to some of these reliability standards. Under the national standards, utilities must, among other things, respond to emergencies within stated time periods, maintain prescribed levels of generation reserves, and follow instructions concerning load shedding. In 2007, FERC also approved limited delegations of authority from NERC to eight regional entities. The delegations authorize each regional entity to propose regional reliability standards for their respective regions that would supplement or exceed the national standards. NERC has also delegated to the regional entities the authority to monitor and enforce compliance with the regional and national reliability standards, subject to NERC and FERC review.

For a majority of 2019, Peak Reliability performed the reliability coordination and interchange authority functions as required under the NERC standards in the Western Interconnection. As of December 3, 2019, Peak Reliability is no longer providing such service.  On November 1, 2019, we began taking service from CAISO for our footprint in the PNM balancing authority and on December 3, 2019, we began taking service from SPP for our remaining footprint.

We are registered in two of the eight regional entities: WECC and MRO. WECC and MRO seek to sustain and improve the reliability of the electric grid through regional coordination, standard setting, certification of grid operators, reliability assessments, coordinated regional planning and operations, and dispute resolution. In addition, our generating facilities are included in two regional reserve sharing pools: the Northwest Power Pool and the Southwest Reserve Sharing Group. These pools facilitate sharing of generation reserves to be activated during a system emergency such as loss of a generating unit or transmission line.

We have an active compliance monitoring program that covers all aspects of our generation and transmission reliability responsibilities. We also collaborate with our Members on areas where transmission and distribution system reliability responsibilities overlap. NERC and its regional entities, including WECC and MRO, periodically audit compliance with reliability standards. In addition to audits and spot‑checks (unscheduled audits), NERC and its regional entities, including WECC and MRO, also are authorized to conduct other types of investigations, including requiring annual “self‑certifications” of compliance with select reliability standards. In 2015, NERC approved our participation in a new coordinated oversight program as a MRRE, whereby WECC was designated as our Lead Regional Entity. The intent of the MRRE program is to streamline compliance and enforcement efforts for entities registered in multiple regions.

In 2018, we were audited by WECC and are scheduled for a future compliance audit in 2021 as part of a three-year routine audit cycle. WECC has closed out all of the findings from the 2018 audit, and no penalties were assessed.

WECC stated that they have noticed the improvements we have made in our compliance implementation and have a good culture of compliance.

ENVIRONMENTAL REGULATION

We are subject to various federal, state and local laws, rules and regulations with regard to the following:

These laws, rules and regulations often require us to undertake considerable efforts and incur substantial costs to maintain compliance and obtain licenses, permits and approvals from various federal, state and local agencies. To comply with existing environmental regulations, we expect that we will spend approximately $14 million through 2024 in efforts to maintain compliance. We estimate that we spend over $500,000 per year in permit‑related fees, as well as increased operating costs to ensure compliance with environmental standards of the Clean Air Act, described below. If we fail to comply with these laws, regulations, licenses, permits or approvals, we could be held civilly or criminally liable.

Our operations are subject to environmental laws and regulations that are complex, change frequently and have become more stringent and numerous over time. Federal, state and local standards and procedures that regulate the environmental impact of our operations are subject to change. These changes may arise from continuing legislative, regulatory and judicial actions regarding such standards and procedures. Consequently, there is no assurance that environmental regulations applicable to our facilities will not become materially more stringent, or that we will always be able to obtain all required operating permits. An inability to comply with environmental standards could result in reduced operating levels or the complete shutdown of our facilities that are not in compliance. We cannot predict at this time whether any additional legislation or rules will be enacted which will affect our operations, and if such laws or rules are enacted, what the cost to us might be in the future because of such actions.

From time to time, we are alleged to be in violation or in default under orders, statutes, rules, regulations, permits or compliance plans relating to the environment. Additionally, we may need to deal with notices of violation, enforcement proceedings or challenges to construction or operating permits. In addition, we may be involved in legal proceedings arising in the ordinary course of business.

Since 1971, we have had in place a Board Policy for Environmental Compliance that is reviewed each year by our Board. The policy commits us to comply with all environmental laws and regulations. The policy also calls for the enforcement of an internal EMS. We have developed, implemented, and continuously improved the EMS over the last eighteen years. The EMS meets the EPA guidance for management systems and consists of policies, procedures, practices and guides that assign responsibility and help ensure compliance with environmental regulations.

State Environmental and Renewable Portfolio Standards Legislation

The Colorado General Assembly in 2019 passed House Bill 19-1261, Climate Action Plan to Reduce Pollution, which was signed by the Colorado Governor on May 30, 2019. The legislation requires that the Air Quality Control Commission develop rules to reduce statewide greenhouse gas emissions 26 percent by 2025, 50 percent by 2030, and 90 percent by 2050, relative to 2005 emissions. The Colorado legislation will have a material impact on our operations and our future generation portfolio; however, until the final rules are enacted that implement the legislation, it is not yet possible to estimate the impacts on our operations or future generation portfolio. The Air Quality Control Commission has not yet developed or adopted rules to implement the legislation.

The New Mexico Legislature in 2019 passed Senate Bill 489, the Energy Transition Act, which was signed into law by the New Mexico Governor on March 22, 2019. The legislation amends the existing RPS that requires our New

Mexico Members to obtain 9 percent and 10 percent of their energy requirements from renewable sources in 2019 and 2020, respectively. The legislation adds requirements for our New Mexico Members to obtain 40 percent renewable energy by 2025 and 50 percent renewable energy by 2030, and adds a target of achieving a zero carbon resource standard by 2050, with at least 80 percent renewable energy. The legislation includes regulatory relief for the 2050 target, if implementing the provisions of the bill are not technically feasible, hampers reliability or increases cost of electricity to unaffordable levels.

The existing Colorado RPS law requires our Colorado Members to obtain at least 6 percent in 2019 and 10 percent in 2020 and thereafter of their energy requirements from renewable sources and requires we provide to our Colorado Members at least 20 percent in 2020 and thereafter of the energy at wholesale from renewable resources. The Colorado law permits us to count renewable sources utilized by our Colorado Members for their RPS requirement towards compliance with our separate RPS requirement.

We currently provide sufficient energy from renewable sources to meet our Members’ current obligations under the RPS requirements in New Mexico and Colorado and expect to be able to continue meeting our Members’ RPS obligations in 2020 to the extent a Member does not meet its obligation with renewable generation owned or controlled by such Member as permitted under our wholesale electric service contract. We expect to be able to achieve compliance with our separate RPS that requires 20 percent of the energy we provide to our Colorado Members at wholesale come from renewable sources in 2020.

The impacts of the 2019 Colorado and New Mexico legislation could include modifications to the design or operation of existing facilities, increases in our operating expenses and potential stranded costs, investments in new generation and transmission, the closure of additional generating facilities, the closure of individual coal-fired generating facilities earlier than announced as part of our Responsible Energy Plan, and other impacts additional to the closures of coal-fired generating facilities associated with the Responsible Energy Plan. See “– MEMBERS – Responsible Energy Plan” for information on our Responsible Energy Plan.

Air Quality

The Clean Air Act.  Pursuant to the Clean Air Act, the EPA has adopted standards regulating the emission of air pollutants from generating facilities and other types of air emission sources, establishing national air quality standards for major pollutants, and requiring permitting of both new and existing sources of air pollution. The Clean Air Act requires that the EPA periodically review, and revise if necessary, its adopted emission standards and national ambient air quality standards. Both of these actions can impose additional emission control and compliance requirements, increasing capital and operating costs. Among the provisions of the Clean Air Act that affect our operations are (1) the acid rain program, which requires nationwide reductions of SO₂ and NOx from existing and new fossil fuel‑based generating facilities, (2) provisions related to major sources of toxic or hazardous pollutants, (3) New Source Review, which includes requirements for new plants that are major sources and modifications to existing major source plants, (4) National Ambient Air Quality Standards that establish ambient limits for criteria pollutants, and (5) requirements to address visibility impacts from regional haze. Many of the existing and proposed regulations under the Clean Air Act impact coal‑fired generating facilities to a greater extent than other sources.

Our facilities are currently equipped with pollution controls that limit emissions of SO₂, NOx, and particulates below the requirements of the Clean Air Act and our permits. As needed, some specified units have appropriate mercury emission controls. We have pollution control equipment on each of our generating facilities. All three units at Craig Station have scrubbers to remove SO₂, baghouses for particulate removal and low NOx burners. Craig Station Unit 2 has selective catalytic reduction equipment for NOx control. Craig Station Unit 3 has selective non-catalytic reduction equipment for NOx control and an activated carbon injection system to control mercury emissions. Escalante Station has scrubbers to remove SO₂, baghouses for particulate removal, a laser-based system to optimize combustion for NOx emissions, and an activated carbon injection system to control mercury emissions. Springerville Unit 3 has scrubbers to remove SO₂, baghouses for particulate removal, low NOx burners and selective catalytic reduction equipment for NOx control, and an activated carbon injection system for controlling mercury emissions.

Basin, as the operator for the Laramie River Generating Station, is responsible for environmental compliance and reporting for that facility. TEP is the operator of Springerville Unit 3 and is responsible for environmental compliance of that station. Springerville Unit 3 operates under a Title V air permit that was issued for all Springerville Generating Station units. Springerville Unit 3 was designed and constructed to comply with permitted Best Available Control Technology emission standards. If liabilities arise as a result of a failure of environmental compliance at Laramie River Generating Station or Springerville Unit 3, our respective responsibility for those liabilities is governed by the operating agreements for the facilities.

We own and operate combustion turbine generating facilities that burn natural gas and/or fuel oil at five locations in Colorado and one in New Mexico. The combustion turbines are subject to emission limits lower than those of coal‑fired generating facilities. All units have the necessary air and water permits in place and are operated in accordance with regulatory provisions. Steam turbine facilities include steam injection to control NOx emissions by lowering thermal NOx formation.

Acid Rain Program.  The acid rain program requires nationwide reductions of SO₂ and NOx emissions by reducing allowable emission rates and by allocating emission allowances to generating facilities for SO₂ emissions based on historical or calculated levels, and reducing allowable NOx emission rates. An emission allowance, which gives the holder the authority to emit one ton of SO₂ during a calendar year, is transferable and can be bought, sold or banked in the years following its issuance. Allowances are issued by the EPA. The aggregate nationwide emissions of SO₂ from all affected units are now capped at 8.95 million tons per year. We receive and hold sufficient SO₂ allowances for compliance with the acid rain program and send excess allowances back to our general account. Allowances have been issued by EPA through compliance year 2046 and we have additional general account allowances that would provide for additional years based on our current usage rate.

Greenhouse Gas Regulation.    On October 23, 2015, the EPA published in the Federal Register a final rule regarding emission limits and emission guidelines of CO₂ for existing generating facilities in a comprehensive rule referred to as the “Clean Power Plan.” The Clean Power Plan established guidelines for states to develop plans to limit emissions of CO₂ from existing units. The goal of the rule was a reduction in CO₂ emissions from 2005 levels of 32 percent nationwide by 2030 and specifies interim emission rates phasing in between 2022 and 2029.

On February 9, 2016, the United States Supreme Court granted numerous applications to stay the Clean Power Plan pending judicial review. On October 16, 2017, the EPA published a proposal to repeal the Clean Power Plan. In July 2019, the EPA finalized the repeal of the Clean Power Plan. 

On August 31, 2018, the EPA published in the Federal Register a proposed rule regarding emission guidelines for greenhouse gas emissions from existing generating units, commonly referred to as the Affordable Clean Energy rule. The Affordable Clean Energy rule is intended to replace the Clean Power Plan. In July 2019, the EPA finalized the Affordable Clean Energy rule which establishes guidelines for states to follow in developing limitations (i.e., standards of performance) for CO₂ emissions from existing units, based on an EPA determination that the best system of emission reduction is heat rate improvement. While the Affordable Clean Energy rule establishes that requirements be achievable based on adequately demonstrated technology, implementation of the rule will be at the state level, and it is too early to know how each state in which we operate will administer the rule. If a state implements a very strict interpretation of the rule, it may have a material impact on our operations. Legal actions were filed in opposition to and support of the Affordable Clean Energy rule. The D.C. Circuit Court of Appeals issued a briefing order indicating that briefing in the case will be complete by July 30, 2020. It is unlikely that legal arguments will take place before fall 2020, and a decision is unlikely for several months after that.

The EPA also issued a final NSPS for new units, which established CO₂ emission standards for new, modified and reconstructed units. On April 4, 2017, the EPA published in the Federal Register a notice that the EPA is reviewing and, if appropriate, will initiate proceedings to suspend, revise or rescind this NSPS. On August 8, 2017, the D.C. Circuit Court of Appeals issued an order to hold the legal proceeding in abeyance indefinitely and directed the EPA to file status reports at ninety-day intervals beginning October 27, 2017.

On December 20, 2018, the EPA published a proposed rule to revise the NSPS for new, modified, and reconstructed units. The EPA has yet to finalize this rulemaking.

Mercury and other Hazardous Air Pollutants.  The Clean Air Act also provides for a comprehensive program for the control of hazardous air pollutants, including mercury. The EPA must treat mercury as a “hazardous air pollutant” subject to a requirement to install MACT in new and existing units. In 2012, the EPA finalized a MACT rulemaking with emissions standards across four categories of emissions. We believe we are in compliance with the rule’s emission limits at our generating facilities and have the appropriate emission controls.

On December 26, 2018, the EPA signed a proposed rule to reconsider a supplemental finding related to the MACT rulemaking that has to do with consideration of costs. The proposal would not change the compliance obligations. In addition, the proposal would offer EPA’s statutorily-required residual risk and technology review, the results of which are that current standards are protective and no new developments in hazardous air pollutant controls to achieve further cost-effective emission reductions were identified. The EPA has yet to finalize this rulemaking.

New Mexico, Colorado and Arizona adopted rules that require mercury monitoring and contain emission limits. Our coal‑fired facilities are subject to these regulations. We have installed mercury monitors and comply with the state rules. In light of the federal rule, New Mexico repealed its state rule in 2014 and Colorado in 2015 amended its state rule to lessen the regulatory burden.

New Source Review.  Section 114(a) Information Requests related to New Source Review Program Requirements. Over the past two decades, the United States Department of Justice, on behalf of the EPA, has brought enforcement actions against owners of coal‑fired facilities alleging violations of the New Source Review provisions of the Clean Air Act in cases where emissions increased without commensurate installation or upgrades of pollution controls. Such enforcement actions were brought against facilities after review by the EPA of operations and maintenance records of the facilities. The EPA has the authority to review such records pursuant to Section 114 of the Clean Air Act. To date, we have not been issued an information request for EPA review of the records of any of our facilities, and therefore, are not involved in any enforcement action from past operational and maintenance activities.

National Ambient Air Quality Standards.  In October 2015, the EPA lowered the NAAQS for ozone from 75 ppb to 70 ppb. The J.M. Shafer Generating Station and Knutson Generating Station are located in the DM/NFR ozone nonattainment area. The DM/NFR area did not meet the 2008 ozone NAAQS of 75 ppb and this area is not anticipated to meet the 2015 ozone NAAQS that was set at 70 ppb. In December 2019, the EPA reclassified the DM/NFR ozone nonattainment area from “moderate” to “serious” nonattainment for the 2008 ozone NAAQS of 75 ppb. Currently, it is not anticipated that additional areas will be designated as nonattainment for the more stringent 2015 ozone standard. It is expected that the DM/NFR ozone nonattainment area will be required to submit a plan to comply with the 2015 ozone NAAQS by 2021. Implementation of an ozone standard of 70 ppb will require the evaluation of additional emission controls for all major sources in the DM/NFR nonattainment area. Additional emission controls may or may not be required at the J.M. Shafer Generating Station and the Knutson Generating Station.

Regional Haze.  On June 15, 2005, the EPA issued the Clean Air Visibility Rule, amending its 1999 Regional Haze Rule, which had established timelines for states to improve visibility in national parks and wilderness areas throughout the United States. Under the amended rule, certain types of older sources may be required to install BART and states were to establish Reasonable Progress Goals in SIPs to meet a 2064 goal of natural visibility conditions. The amended Regional Haze Rule could require additional controls for particulate matter, SO₂ and NOx emissions from utility sources.

The states were required to develop their regional haze implementation plans by December 2007, identifying the facilities that would need to undergo BART determinations. The Reasonable Progress phase of meeting the Regional Haze Rule is the development of periodic visibility goals in order to meet a 2064 goal of natural visibility conditions. The Reasonable Progress phase SIPs establish standards and a timeline for meeting visibility goals. Colorado, New Mexico, Wyoming and Arizona previously developed their first SIPs, which are described below, and are now developing their second SIPs, which are due to the EPA by July 2021.

Under the existing, approved Colorado’s SIP, we committed to NOx emissions rates that resulted in the installation of selective catalytic reduction on Craig Station Unit 2 and the owners of Craig Station Unit 1 will retire Craig Station Unit 1 by December 31, 2025 without any installation of selective catalytic reduction prior to its retirement.

Any source that emits SO₂, NOx, and particulates and that may contribute to the degradation of visibility in national parks and wilderness areas, identified as Class I areas, could be subject to additional controls. New Mexico opted to comply with SO₂ provisions of the Regional Haze Rule by putting in place a backstop SO₂  trading program. Arizona and New Mexico evaluated NOx emission impacts on visibility and moved forward to develop Reasonable Progress rules for NOx reductions. New Mexico’s plan includes the closure of two units at San Juan Generating Station, including Unit 3, but neither state’s current plan requirements affect our current assets. In Wyoming, after a settlement was reached in late 2016, selective non-catalytic reduction was installed on Laramie River Generating Station Units 2 and 3.

The Regional Haze Rule requires that states revise their SIPs every ten years. Therefore, like many environmental requirements, the Regional Haze Rule could require further reductions if needed to meet Reasonable Progress goals in the future.

State Implementation Plans.  On June 12, 2015, the EPA published a final action in the Federal Register that takes action under the Clean Air Act, enacting SIP calls in states to change provisions to the current affirmative defense to civil penalties used by permitted sources, including electric utilities, in the event they have emissions during a startup, shutdown or malfunction event that are in excess of permitted limits. States retain broad discretion concerning how to revise their SIP, so long as that revision is consistent with the requirements of the Clean Air Act. The EPA issued the SIP call for 36 states, including Arizona, Colorado, New Mexico, and Wyoming. The EPA established a deadline of November 22, 2016, by which those states must have made SIP submissions to rectify the specifically identified deficiencies in their respective SIPs. Colorado completed a rulemaking process wherein the affirmative defense provisions were retained in federal court proceedings, should a federal court wish to consider the affirmative defense provisions. New Mexico and Arizona completed rulemakings wherein the affirmative defense provisions were removed from SIPs and maintained as state regulatory provisions. At this time, we cannot predict the outcome of the EPA’s consideration of these submittals.

Water Quality

The Clean Water Act.  The Clean Water Act regulates the discharge of process wastewater and certain storm water under the NPDES permit program. At the present time, we have the required permits under the program for all of our generating facilities. The water quality regulations require us to comply with each state’s water quality standards, including sampling and monitoring of the waters around affected plants.

As permitted by the State of Colorado under the Colorado Discharge Permit System (a delegated NPDES program), Rifle Generating Station discharges process wastewater to nearby water bodies. Rifle Generating Station discharges to a dry ditch (unnamed tributary to Dry Creek) that flows to the Colorado River. J.M. Shafer Generating Station discharges indirectly under an EPA pretreatment permit to the City of Fort Lupton wastewater treatment facility through a pond system. Our other facilities have on‑site containment ponds where water is evaporated and have no surface water discharges. We also have NPDES storm water permits for Craig Station and Escalante Station. We maintain Stormwater Pollution Prevention Plans as required in the stormwater permits to ensure that stormwater run‑off is not impacted by industrial operations. We currently have construction stormwater permits for numerous transmission line and generation construction projects. These construction permits will be terminated once adequate vegetation is established at the sites, which can take several growing seasons. Escalante Station and Pyramid Generating Station have groundwater discharge permits administered by the New Mexico Environment Department, which governs the pond systems at both facilities and on‑site ash landfill at Escalante Station. The pond systems are designed to reuse or store and evaporate water.

Section 316(b) of the Clean Water Act requires the EPA to ensure that the location, design, construction and capacity of cooling water intake structures reflect the best technology available to protect aquatic organisms from being

killed or injured by impingement or entrainment. Section 316(b) is applicable to Craig Station; however, impacts are minor as the facility operates a closed cycle cooling system minimizing impingement and entrainment.

On March 6, 2017, the EPA and the U.S. Army Corps of Engineers published in the Federal Register a notice that it intended to revise and rescind or revise the 2015 expansion of regulatory authority under the Clean Water Act through broadening the definition of WOTUS and identified a two-step process regarding the definition of WOTUS. Step one was a proposal to withdraw the 2015 definition of WOTUS, which was finalized in September 2019. Step two is a new WOTUS definition, which the EPA and the U.S. Army Corps of Engineers announced on January 23, 2020.

Spill Prevention Control and Countermeasures.  The EPA issued regulations governing the development of Spill Prevention Control and Countermeasures plans. Some of our substation and generation sites are subject to these regulations and all Spill Prevention Control and Countermeasures plans meet the regulations.

Other Environmental Matters

Coal Ash.  We manage coal combustion by‑products such as fly ash, bottom ash and scrubber sludge by removing excess water and placing the by-products in land-based units in a dry form. At Craig Station, the combustion by‑products are used for mine land reclamation at the adjacent coal mine. At Escalante Station, the combustion by‑products are placed in designated landfills. The mine‑fill and landfills are regulated by state environmental agencies and all required permits are in place. In 2010, the EPA proposed two options for regulating combustion by‑products under RCRA. One option is regulation as a solid waste under RCRA Subtitle D; the second option is regulation as a hazardous waste under Subtitle C. The EPA in December 2014 announced that it chose to pursue regulations as a solid waste under Subtitle D of RCRA. The final Coal Combustion Residual rule was published in the Federal Register on April 17, 2015. The rule contains varying deadlines for the various compliance obligations, some of which needed to be met by the initial compliance deadline of October 19, 2015. The final federal rule is self-implementing and thus affected facilities must comply with the new regulations even if states do not adopt the rule. We estimate our total costs relating to the management of such by‑products to be approximately $10 million over the life of our facilities. We are meeting all initial compliance obligations that became effective on October 19, 2015. In December 2016, Congress passed the WIIN Act. The WIIN Act provides for the establishment of state and EPA permit programs for coal ash. The Act provides flexibility for states to incorporate the EPA final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule. The WIIN Act was signed into law by President Obama on December 16, 2016. At this time, we are monitoring state actions and cannot predict state actions or impacts. In August and December 2019, the EPA proposed amendments to the rule to address several technical and compliance-related issues pursuant to a settlement from litigation about the Coal Combustion Residuals rule.

Global Climate Change Regulatory Developments Outside the Clean Air Act.  Consideration of laws and regulations to limit emissions of greenhouse gases is underway at the international, national, regional and state levels. International negotiations will determine what, if any, specific commitments to reduce greenhouse gas emissions will be made by all countries that are party to the United Nations Framework Convention on Climate Change, including the United States. The outcome of the 21st Conference of the Parties held by the United Nations in Paris during December 2015 is a broad international agreement based on non-binding commitments with no enforcement provisions known as the Paris Agreement; therefore, the agreement will not directly dictate any particular emission reduction obligations for United States businesses. Commitments are subject to review every five years under the agreement. On July 1, 2017, President Trump announced that the United States would begin a process to withdraw from the Paris Agreement.

The Comprehensive Environmental Response, Compensation and Liability Act.  CERCLA (also known as Superfund) requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties liable for the release to take or pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to a site. To our knowledge, we are not currently subject to liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur liability under CERCLA in the future.

Collom Air Permit. On July 25, 2018, the Center for Biological Diversity and Sierra Club filed a complaint against the CDPHE in opposition to CDPHE’s issuance of an air permit for construction and operation of the Collom pit at the Colowyo Mine. We and Colowyo Coal on August 23, 2018 filed an unopposed motion to intervene and answer to the complaint. The CDPHE on September 4, 2018 filed an answer and defenses to the complaint. On February 14, 2019, the court issued a stay of the case proceedings until May 1, 2019, while CDPHE processes a permit revision. As the permit revision was still pending on April 30, 2019, we filed a Motion for Stay Extension. On May 21, 2019, the Center for Biological Diversity and Sierra Club filed an Opposition to Motion for Stay Extension. On May 28, 2019, the court granted our motion to extend the stay until October 29, 2019. On August 13, 2019, CDPHE issued the public notice for commenting on the revision to the air permit. The 60-day public comment period began on August 14, 2019 and ended on October 12, 2019. We filed selective comments on October 11, 2019. 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. On December 20, 2019, all parties agreed to file a Joint Motion to Dismiss the litigation on the original air permit. On January 16, 2020, the judge granted the Joint Motion to Dismiss the original Collom air permit case. In regard to the new case, we filed a motion to intervene as an intervenor-defendant on January 28, 2020.

Mine Reclamation.  The EPA is working with the OSMRE and state mine reclamation regulators to develop a better understanding of mine placement practices for coal ash. The OSMRE may issue a proposed rulemaking establishing requirements and standards that apply when coal ash is used during reclamation at surface coal mining operations. However, recent regulatory agendas indicate that OSMRE is not actively pursuing these plans. Until these rules might be promulgated, we cannot determine what, if any, controls we may be required to implement to comply with the regulation.

Toxic Substances Control Act/Polychlorinated Biphenyls.  We have limited quantities of PCBs in transmission equipment in the existing system. As oils are changed and systems replaced, PCBs are eliminated and PCB‑free oils are used, reducing regulatory risk. 

Endangered Species Act.  Past litigation from environmental groups resulted in the U.S. Fish and Wildlife Service being placed on a schedule to make determinations as to whether or not numerous species should be formally listed as threatened or endangered under the Endangered Species Act. Once listed, a species of animal or plant with threatened or endangered status may complicate, delay, and/or add costs to projects. Of the several hundred species involved in the litigation settlement, we estimate that approximately 30 had the potential to affect our operations. Species of particular concern due to their geographic range and potential impacts to mining and transmission assets are the greater sage‑grouse, the Gunnison sage‑grouse, and the lesser prairie‑chicken. In September 2015, the U.S. Fish and Wildlife Service determined that it was not warranted to list the greater sage-grouse under the Endangered Species Act, in large part due to federal land management agency conservation plans. The Bureau of Land Management and U.S. Forest Service conservation plans from 2015 were reviewed and revised further during 2017 and 2018. We commented in 2017 and 2018 during the Bureau of Land Management’s review process. The Gunnison sage-grouse was addressed in amendments to a local Bureau of Land Management Resource Management Plan and the U.S. Fish and Wildlife Service may issue a Special 4(d) rule for the species in the future. After its listing as a threatened species was vacated, the lesser prairie-chicken underwent another review under the Endangered Species Act. A decision whether or not to list the lesser prairie-chicken was expected in 2018 but was not released. We are monitoring each of these issues as they develop over time. In addition to species-specific actions, the U.S. Fish and Wildlife Service in 2018 proposed three rules aimed at improving various regulatory and compliance processes under the Endangered Species Act. In August 2019, the U.S. Fish and Wildlife Service finalized the three reform rules.

ITEM 1A.RISK FACTORS

Our business, financial condition or results of operations could be materially adversely affected by various risks, including those described below.

Successful state or federal jurisdictional claims in  Member withdrawal disputes may materially impact our financial condition, results of operations and our long-term debt. 

Pursuant to our Bylaws, a Member may withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no 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. By the addition of a non-cooperative member in 2019 and specifically by the addition of MIECO, Inc. as a member on September 3, 2019, we became a FERC jurisdictional “public utility” under Part II of the FPA.  In November 2019, United Power and LPEA filed complaints with the COPUC alleging that the COPUC has jurisdiction over the equitable terms and conditions as our Board may prescribe for withdrawal and seeking the COPUC to establish a withdrawal number or exit charge. In December 2019, we filed our Petition for Declaratory Order with FERC asking FERC to confirm our jurisdictional 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.  Some of the interveners and protestors in our Petition for Declaratory Order, including some of our Members and the COPUC, are alleging that we are not FERC jurisdictional and are still exempt from FERC wholesale rate regulation pursuant to the FPA.  See “LEGAL PROCEEDINGS.”

If the COPUC or any other state commission or state regulatory body is successful in asserting that it has jurisdiction over the terms and conditions for a Member’s withdrawal from us, including the complaints filed by United and LPEA, and if the COPUC or any other state jurisdiction or state regulatory body determines the terms and conditions for a Member to withdraw that are less than the monetary value as our Board may proscribe, it may materially impact us.  If we are successful in asserting that FERC has sole jurisdiction over the terms and conditions for a Member’s withdrawal from us and FERC determines the terms and conditions for a Member to withdraw that are less than the monetary value as our Board may proscribe, it may materially impact us. In addition, if we underestimate the monetary value of a Member’s obligation or a significant number of our Members withdraw, it may materially impact us.

The material impacts could include increased rates to our Members, a materially adverse effect on our financial condition and results of operations, and we may be required to offer a prepayment of certain of our long-term debt, without paying a make-whole amount. In addition, an offer of prepayment or prepayment of certain of our long-term debt could be viewed by lenders as triggering an event of default under the cross-default provision of our other loan agreements, including our Revolving Credit Agreement that provides backup for our commercial paper program. If such debt is accelerated due to the cross-default provision and we are unable to pay such accelerated debt, our lenders could assert that there is an event of default under the Master Indenture.

Our ability to raise our Members’ wholesale rates is limited and we are subject to rate regulation.

Wholesale rate increases for our Members must be approved by a majority of our Board, which is comprised of one representative from each of our 43 Members and is now also subject to FERC’s approval. By the addition of a non-cooperative member in 2019, and specifically by the addition of MIECO, Inc. as a member on September 3, 2019, we became FERC jurisdictional for our Member rates, transmission service, and our market based rates.  We filed our tariffs for wholesale electric service and transmission at FERC in stages between December 23 and 27, 2019, with supplemental filings completed by December 30, 2019. Our existing Class A wholesale rate structure (A-40) to our Members was filed at FERC as a “stated rate” where we requested FERC to approve the existing rate as stated.  We expect FERC to rule on their acceptance of these tariffs, including our existing wholesale rate structure to our Members, by the end of March 2020. See ‘‘LEGAL PROCEEDINGS.” Upon our next rate change, we will be required to justify the new rates to our Members at FERC with a rate case, likely to be contested.

Challenges to the rates approved by our Board and filed with FERC for approval could make it difficult for us to adjust the wholesale rates to our Members as completely or rapidly as necessary in response to changes in our operations or market conditions, which could have an adverse effect on our results of operations and financial condition.

Furthermore, our ability to create a regulatory asset to defer expenses associated with the early retirements of our generating facilities to implement the Responsible Energy Plan or the utilization of regulatory liabilities to ensure our Member rates remain stable, during this transition to a cleaner generation portfolio requires FERC approval. If we are unable to obtain FERC approval, it could have the effect of increasing the cost of electric service we provide to our Members and, as a result, could affect their ability to perform their contractual obligations to us. In addition, we may experience additional Member unrest and desires to withdrawal from our Members.

FERC may also review our rates upon its own initiative or upon complaint and order a reduction of any rates determined to be unjust, unreasonable, or otherwise unlawful and order a refund for amounts collected during such proceedings in excess of the just, reasonable, and lawful rates.

We were operating as a FERC-jurisdictional public utility making sales and providing services without satisfying the FPA’s filing obligations and FERC’s prior notice requirement.  We may be subject to certain penalties, fines and/or refunds.

On July 23, 2019, we filed with FERC our initial tariff, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. Our FERC tariff filing included our current Class A rate schedule for electric power sales to our Members as the wholesale rates payable by our Members.  On September 3, 2019, a membership agreement with a non-utility member, MIECO, Inc., became effective and we notified FERC of such and requested a partial waiver. The admission of the new 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 FPA.  On October 4, 2019, FERC issued an order rejecting our filings without prejudice to us submitting a more complete set of filings that cure the deficiencies set forth in such order.  During the week of December 23, 2019, we filed our revised set of filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. Until we made our reapplication in December 2019, we were a FERC-jurisdictional public utility making sales and providing services without satisfying the FPA’s filing obligations and FERC’s prior notice requirements. FERC may require us to refund to our customers certain amounts collected for the entire period that the rate was collected without FERC’s authorization, including Member and non-member electric sales and wheeling revenue.  FERC may also impose civil penalties for the time period between when we became a FERC-jurisdictional public utility and when we made our reapplication in December 2019. Furthermore, current practices including our use of regulatory assets are subject to FERC approval and subject to change as a result. It is not possible to predict if FERC will require us to refund amounts, the scope of such refunds to our customers, if FERC will impose civil penalties, if FERC will approve our current practices regarding use of regulatory assets, or to estimate any liability associated with this matter. In addition, our customers may dispute their obligation to pay us or pay under protest because we do not have FERC approved rates.

Although we expect that our revised filings with FERC will cure the deficiencies set forth in FERC’s rejection of our initial filing, there is no guarantee that FERC will accept our revised filing, that FERC will accept our revised filing subject to refund or that FERC will conclude that we are a FERC- jurisdictional “public utility.”

By the addition of a non-cooperative member in 2019 and specifically by the addition of MIECO, Inc. as a member on September 3, 2019, we became a FERC-jurisdictional “public utility” under Part II of the FPA. On October 4, 2019, FERC issued an order rejecting our initial July 23, 2019 filings without prejudice to us submitting a more complete set of filings that cure the deficiencies set forth in such order. During the week of December 23, 2019, we filed our revised set of filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. Some of the interveners and protestors in our revised tariff filing, including some of our Members and the COPUC, are alleging that we are not FERC jurisdictional and are still exempt from FERC wholesale rate regulation pursuant to the FPA. There can be no guarantee that FERC will accept our revised filings or that FERC will conclude or rule on our status as a FERC-jurisdictional “public utility.” If FERC rejects our revised filing or does not conclude or rule on our status of a FERC-jurisdictional “public utility,” our future business plans may be impacted. If FERC does not conclude or rule on

our status of a FERC-jurisdictional “public utility,” we may be subject to further and increased pressure by the states, including the COPUC, to regulate our rates and charges to our Members, including the withdrawal number or exit charges associated with Member withdrawals and any buy-down numbers associated with partial requirements contracts. If FERC accepts our filing subject to refund, we may be required to accrue certain liabilities associated with the amounts subject to refund and may be required to refund certain revenue collected.

Our Responsible Energy Plan may not achieve Member, environmentalist, lender, local community, or other stakeholder acceptance which may impact our financial condition or future plans.

In January 2020, we announced the actions of our Responsible Energy Plan whereby we outlined our intention to early retire certain of our coal-fired generating facilities, reduce emissions and increase our renewable portfolio, and provide community support for transitioning communities.  Although we believe that our Responsible Energy Plan addresses Member concerns regarding access to more renewable energy, addresses environmentalist concerns regarding clean energy, addresses lender concerns regarding increasing our renewable energy portfolio, and provides assistance to transitioning communities, there can be no guarantee that these stakeholders or other stakeholders not identified herein will be receptive to our Responsible Energy Plan or believe that our Responsible Energy Plan addresses their concerns.  If our Members, environmentalists, lenders, local communities, or other stakeholders do not accept our Responsible Energy Plan or believe that we have adequately addressed their concerns through the adoption of our Responsible Energy Plan, we may experience additional Member unrest and desires to withdrawal, unfavorable media coverage or other negative consequences which may impact our financial condition or future plans.  

Compliance with existing and future environmental laws and regulations, including RPS, may increase our costs of operation and further affect the utilization of current generation facilities.

As with most electric utilities, we are subject to extensive federal, state and local environmental requirements that regulate, among other things, air emissions, water discharges and use and the management of hazardous and solid wastes. Compliance with these requirements requires significant expenditures for the installation, maintenance and operation of pollution control equipment, monitoring systems and other equipment or facilities. In 2019, our existing generating facilities generated approximately 61.5 percent of our energy available for sale, a substantial percentage of which is generated by coal-fired generating facilities.

Existing and any additional federal or local environmental restrictions imposed on our operations, including RPS requirements imposed on us or our Members, could result in significant additional costs, including capital expenditures. Implementation of regulations on existing legislation or more stringent standards may require us to modify the design or operation of existing facilities or purchase emission allowances. In addition, implementation of regulations on existing legislation or more stringent standards or costs could further affect generating facilities retirement and replacement decisions, including the shutting down of additional generating facilities or the shutting down of individual coal-fired generating facilities earlier than announced as part of our Responsible Energy Plan, and may substantially increase the cost of electricity to our Members. The cost impact of the implementation of regulation on existing legislation and future legislation or regulation will depend upon the specific requirements thereof and cannot be determined at this time, but could be significant, including, increases in our operating expenses and potential stranded costs, and investments in new generation and transmission. Examples of existing legislation and the implementation regulations to address limitations on CO₂ emissions and RPS are discussed below.

The Colorado General Assembly in 2019 passed House Bill 19-1261, Climate Action Plan to Reduce Pollution, which was signed by the Colorado Governor on May 30, 2019. The legislation requires that the Air Quality Control Commission develop rules to reduce statewide greenhouse gas emissions 26 percent by 2025, 50 percent by 2030, and 90 percent by 2050, relative to 2005 emissions. The Air Quality Control Commission has not yet developed or adopted rules to implement the legislation.

The New Mexico Legislature in 2019 passed Senate Bill 489, the Energy Transition Act, which was signed into law by the New Mexico Governor on March 22, 2019. The legislation amends the existing RPS that requires our New Mexico Members to obtain a percentage of their energy requirements from renewable sources. The legislation adds requirements for our New Mexico Members to obtain 40 percent renewable energy by 2025 and 50 percent renewable

energy by 2030, and adds a target of achieving a zero carbon resource standard by 2050, with at least 80 percent renewable energy. The legislation includes regulatory relief for the 2050 target, if implementing the provisions of the bill are not technically feasible, hampers reliability or increases cost of electricity to unaffordable levels.

In July 2019, the EPA finalized the Affordable Clean Energy rule. The Affordable Clean Energy rule establishes guidelines for states to follow in developing limitations (i.e. standards of performance) for CO₂ emissions from existing units, based on an EPA determination that the best system of emission reduction is heat rate improvement. While the Affordable Clean Energy rule establishes that requirements be achievable based on adequately demonstrated technology, implementation of the rule will be at the state level, and it is too early to know how each state in which we operate will administer the rule. If a state implements a very strict interpretation of the rule, it may have a material impact on us.

Litigation relating to environmental issues, including claims of property damage or personal injury caused by greenhouse gas emissions, has increased generally throughout the United States. Likewise, actions by private citizen groups to enforce environmental laws and regulations are becoming increasingly prevalent.

There can be no assurance that we will always be in compliance with all environmental requirements or that we will not be subject to future or additional RPS requirements. Failure to comply with existing and future requirements, even if this failure is caused by factors beyond our control, could result in civil and criminal penalties and could cause the complete temporary or permanent shutdown of individual generating units not in compliance with these regulations.

We operate in a capital-intensive industry and therefore debt comprises a majority of our capital structure.

As of December 31, 2019, we had total debt and short-term borrowings outstanding of approximately $3.4 billion, of which approximately $2.8 billion was secured under our Master Indenture. We have incurred indebtedness primarily to construct, acquire, or make capital improvements to generation and transmission facilities to supply the current and projected electricity requirements of our Members and to meet our other long-term electricity supply obligations. If demand for electricity from our Members and under our long-term power sales agreements is materially less than projected, we might not generate sufficient revenue to meet the DSR and ECR requirements in our Master Indenture or to service our indebtedness. If this occurs, we may be required to raise our rates, revise our plans for capital expenditures and/or restructure our long-term commitments. These actions may adversely affect our operations, and we may be unable to generate sufficient additional revenue to pay our obligations. Further, failure to meet the ECR requirement in our Master Indenture or failure to service the indebtedness secured by the Master Indenture would result in an event of default under the Master Indenture and other loan agreements. As a consequence, our results of operations, liquidity and financial condition could be adversely affected.

We expect we will need to construct or acquire additional generation, including energy storage facilities such as batteries, and transmission facilities to meet our Members’ demands, to comply with new CO₂ reduction and RPS legislation, and to implement our Responsible Energy Plan, which may require substantial additional capital expenditures which may increase our long-term debt, or for which we may not be able to obtain financing, and may result in development uncertainties for our business.

Our ability to access short-term and long-term capital and our cost of capital could be adversely affected by various factors, including credit ratings and current market conditions, and significant constraints on our access to capital and could adversely affect our financial condition and future results of operations.

We rely on access to short-term and long-term capital for construction of new facilities and upgrades to our existing facilities and as a significant source of liquidity for capital expenditures not satisfied by cash flow generated from operations. In the years 2020 through 2024, after taking into account our Responsible Energy Plan, we estimate that we may invest approximately $877 million in new facilities and upgrades to our existing facilities which may require us to take on additional long-term debt.

Our access to capital could be adversely affected by various factors and certain market disruptions could constrain, at least temporarily, our ability to maintain sufficient liquidity and to access capital on favorable terms, or at all. These factors and disruptions include:

•market conditions generally;

•an economic downturn or recession;

•instability in the financial markets;

•a tightening of lending and borrowing standards by banks and other credit providers;

•financial markets view that climate change and emissions of CO₂ are a financial risk;

•the overall health of the energy industry and the generation and transmission cooperative sector;

•negative events in the energy industry, such as a bankruptcy of an unrelated energy company;

•war or threat of war; or

•terrorist attacks or threatened attacks on our facilities or the facilities of unrelated energy companies.

If our ability to access capital becomes significantly constrained for any of the reasons stated above or any other reason, our ability to finance ongoing capital expenditures required to maintain existing facilities and to construct future facilities could be limited, our interest costs could increase and our financial condition and results of operations could be adversely affected.

We are exposed to market risk, including changes in interest rates and availability of capital in credit markets. The interest rates on these future borrowings could be significantly higher than interest rates on our existing debt. As of December 31, 2019, we had $527.7 million of debt with variable rates. The rates on this debt could increase.

We maintain the Revolving Credit Agreement which provides backup for our commercial paper program. The facility includes a letter of credit sublimit and a commercial paper backup sublimit, and financial covenants for DSR and ECR consistent with the covenants in our Master Indenture. Failure to maintain these financial covenants or other covenants could preclude us from issuing commercial paper or from issuing letters of credit or borrowing under the Revolving Credit Agreement.

Sustained low natural gas prices could have an adverse effect on the operation of our facilities and our cost of electric service.

The wholesale electricity price generally correlates with the wholesale natural gas price in most regions of the United States. Generally, low gas prices correlate to low wholesale electricity prices and thereby could reduce the competitiveness of our coal-fired generating facilities. Sustained low natural gas prices could negatively impact the economics of operating our coal-fired generating facilities, which could cause the temporary or permanent shutdown of individual coal-fired generating facilities, including the shutting down of additional coal-fired generating facilities or the shutting down of individual coal-fired generating facilities earlier than announced as part of our Responsible Energy Plan, and thereby significantly increasing the cost of electric service we provide to our Members and affecting their ability to perform their contractual obligations to us.

Our financial condition is largely dependent upon our Members.

Our financial condition is largely dependent upon our Members satisfying their obligations under their wholesale electric service contracts with us. In 2019, 92.8 percent of our revenues from electric sales were from our Members. We do not control the operations of our members, and their financial condition is not tied to our results of operations. Accordingly, we are exposed to the risk that one or more of our Members could default in the performance of their obligations to us under their wholesale electric service contract. A default could result from financial difficulties of one or more Members or because of intentional actions by our Members. Our results of operations and financial condition could be adversely affected if a significant portion of our Members default on their obligations to us.

Increased competition could reduce demand for our electric sales.

The electric utility industry has experienced increasing wholesale competition, enabled by deregulation and revisions to existing regulatory policies, competing energy suppliers, including third party energy remarketing companies, new technology, and other factors. The Energy Policy Act of 1992 amended the FPA to allow for increased competition among wholesale electricity suppliers and increased access to transmission services by such suppliers. Competing energy suppliers are targeting our Members by claiming to be able to offer lower priced and cleaner wholesale electric power. This includes assisting our Members in seeking to withdrawal from membership in us and financing the withdrawal number payable by our Members. On the retail side, states in which our Members’ service territories are located do not have retail competition legislation. However, these states could enact retail competition legislation which could reduce our electricity demand from our Members and the pool from which we recover fixed costs, resulting in higher rates to our Members. Competing energy suppliers are also targeting the communities our Members serve by claiming to be able to offer lower priced and cleaner wholesale electric power. It also includes assisting the communities our Members serve by helping them create electric utilities. In addition, federal legislation could mandate retail choice in every state.

We and our Members are subject to regulations issued by FERC pursuant to PURPA with respect to matters involving the purchase of electricity from, and the sale of electricity to, qualifying facilities and co generators. In June 2015, FERC clarified that the 5 percent limitation in our wholesale electric service contracts with our Members related to distributed or renewable generation owned or controlled by our Members did not supersede PURPA and the requirement of our Members to purchase power from qualifying facilities. An increase in the number and/or size of qualifying facilities selling electricity to our Members could reduce our electricity demand from our Members and the pool from which we recover fixed costs, resulting in higher rates to our Members and reduced access to the capital markets.

A number of other significant factors have affected electric utility operations, including the availability and cost of fuel for electric energy generation; the use of alternative fuel sources for space and water heating and household appliances; fluctuating rates of load growth; compliance with environmental and other governmental regulations; licensing and other factors affecting the construction, operation and cost of new and existing facilities; and the effects of conservation, energy management, and other governmental regulations on electric energy use. All of these factors present an increasing challenge to companies in the electric utility industry, including our Members and us, to reduce costs, increase efficiency and innovation, and improve resource management.

We may face competition as a result of the factors described above, including competition from qualifying facilities, other utilities, competing energy suppliers, fuel sources or as a result of technological innovations. Technological innovations may include methods or products that allow consumers to by-pass the electric supplier, to switch fuels or to reduce consumption. These innovations may include, but are not limited to, demand response, distributed generation, energy storage and microgrids. Competition from other utilities and competing energy suppliers may consist of competition from other electric companies, helping our Members withdrawal from membership in us, annexations by municipalities, helping municipalities our Members serve create electric utilities, and competition for the sale of excess power to non-members on both a short-term and long-term basis. If competition increases, additional Members may withdrawal, rates to our Members may increase or our financial condition and results of operations could be adversely affected.

Changes in power generation energy sources could reduce demand for our electric services.

Our mission is to provide our Members with a reliable, affordable and responsible supply of electricity in accordance with cooperative principles. Significant changes are taking place in the electric industry related to self-generation and power generation energy sources such as fuel cells, batteries, micro turbines, wind turbines and solar cells. Adoption of these generation energy sources are continuing to increase because of technological advancements, government subsidies, and a perception that generating electricity through these energy sources is more environmentally friendly than generating electricity with fossil fuels. Increased adoption of these energy sources could reduce electricity demand and the pool of customers from whom fixed costs are recovered or could cause the temporary or permanent shutdown of individual generating units, including the shutting down of additional coal-fired generating facilities or the shutting down of individual coal-fired generating facilities earlier than announced as part of our Responsible Energy

Plan, resulting in higher rates to our Members. Increased self-generation and the related use of net energy metering, which allows our Members’ self-generating customers to receive bill credits for surplus power, could reduce demand for electricity from our Members. If these technologies were to develop sufficient economies of scale and we were unable to adjust our prices to reflect reduced electricity demand and increased self-generation and net energy metering, the competitiveness of our facilities, our financial condition and results of operations could be adversely affected.

Our Members have a substantial number of industrial and large commercial customers who could decrease operations or elect to self-generate in the future.

Based on the most recent information available to us, which is 2018 data, industrial and large commercial customers account for approximately 41 percent of our Members’ energy sales. A large percentage of these sales are in energy production, extraction and transportation. The 15 largest customers of our Members, a substantial percentage of which are in energy production, extraction and transportation, total approximately 17.4 percent of the aggregate retail electric energy sales of our Members, based on the same 2018 data. Outages at facilities of these large customers could reduce demand from and energy sales to our Members. A significant downturn in the economy or sustained low natural gas prices, demand for increased renewable energy, additional federal or local environmental restrictions imposed on their operations, or other changes in business conditions could affect this sector of the energy industry and sales could decrease in the future should these industrial and large commercial customers decide to decrease their operations accordingly or elect to self-generate.

We must make long term decisions involving substantial capital expenditures based on current projections of future conditions.

Our decisions to meet our Members’ load demands by construction of new generation, including energy storage facilities such as batteries, and transmission facilities, by entering into long term power purchase contracts, or by relying on short term power purchase markets are based on long term forecasts. We rely on our forecasts to predict factors affecting our Members’ load demands such as economic conditions, population increases and actions by others in the development of generation and transmission facilities. Even though forecasts are less reliable the farther into the future they extend, we must make decisions based on forecasts that extend decades into the future due to the long lead time necessary to develop and construct new facilities and the long term expected useful life of those facilities.

Our forecasts and actual events may vary significantly, and, as a result, we may not develop the appropriate number or type of generating facilities or rely on technology that becomes less competitive or install transmission facilities in areas where they are not needed. If we over-estimate the growth in our Members’ demand, there is no assurance that the price of surplus power or energy from surplus resources would be economical or could be sold without a loss. If we underestimate the growth in our Members’ demand, we may be required to purchase power or energy at a cost substantially above the cost we would have incurred to obtain the power or generate the energy from owned facilities.

We may experience transmission constraints or limitations to transmission access, and our ability to construct, and the cost of, additional transmission is uncertain.

We currently experience periodic constraints on our transmission system and those of other utilities used to transmit energy from our remote generators to loads due to periodic maintenance activities, equipment failures and other system conditions. We manage these constraints using alternative generation dispatch and energy purchasing patterns. The long-term solution for reducing transmission constraints can include purchasing additional wheeling service from other utilities, or construction of additional transmission lines which would require significant capital expenditures.

As part of our Responsible Energy Plan, we plan to increase our renewable portfolio and as other utilities are also increasing their renewable portfolios, the addition of renewable resources is expected to increase the demand for access to existing transmission lines making it difficult for us to acquire transmission capacity and we expected it will be necessary for us to construct additional transmission lines.

In most cases, construction of transmission lines presents numerous challenges. Environmental and state and local permitting and sitting processes may result in significant inefficiencies and delays in construction. These issues are

unavoidable and are addressed through long term planning. We typically begin planning new transmission at least 10 years in advance of the need and voluntarily participate in regional and interregional transmission planning and cost allocation discussions with neighboring transmission providers. In the event that we are unable to complete construction of planned transmission expansion, we may be unable to implement our Responsible Energy Plan that meets the time and cost expectations of the clean energy transition and we may need to rely on purchases of market priced electric power, which could put increased pressure on electric rates.

We are exposed to cost uncertainty in connection with our construction projects at existing generating facilities, new and existing transmission facilities, and in connection with decommissioning of certain existing generating facilities.

Our existing facilities require ongoing capital expenditures in order to maintain efficient and reliable operations. Many of our generating facilities were constructed over 30 years ago and, as a result, may require significant capital expenditures to maintain efficiency and reliability and to comply with changing environmental requirements.  In the years 2020 through 2024, we estimate that we may invest approximately $482 million in new transmission facilities and upgrades to our existing transmission facilities.

The completion of construction projects is subject to substantial risks, including delays or cost overruns due to:

•shortages and inconsistent quality of equipment, materials and labor;

•sitting, permits, approvals and other regulatory matters;

•unforeseen engineering problems;

•environmental and geological conditions;

•environmental litigation;

•delays or increased costs to interconnect our facilities with transmission grids;

•unanticipated increases in cost of materials and labor; and

•performance by engineering, construction or procurement contractors.

The early retirement of and decommissioning of certain of our existing generating facilities, including Craig Station, Escalante Station, and Nucla Generation Station is subject to substantial risks.  In addition, the early retirement of and decommissioning of additional existing generating facilities before the end of their useful life is subject to substantial risks, including potential requirements to recognize a material impairment of our assets and incur added expenses relating to accelerated depreciation and amortization, decommissioning, reclamation and cancellation of long-term contracts for such generating plants and facilities. Closure of any of such generating facilities may force us to incur higher costs for replacement capacity and energy. The decommissioning costs may exceed our estimate, which could negatively impact results of operations and liquidity. Furthermore, our ability to create a regulatory asset to defer expenses associated with these early retirements or the utilization of regulatory liabilities to ensure our Member rates remain stable, during this transition to a cleaner generation portfolio, requires FERC approval.

All of these risks could have the effect of increasing the cost of electric service we provide to our Members and, as a result, could affect their ability to perform their contractual obligations to us. In addition, we may experience additional Member unrest and desires to withdrawal from our Members.

We could be adversely affected if we or third parties are unable to successfully operate our generating facilities.

Our performance depends on the successful operation of our electric generating facilities. Operating generating facilities involves many risks, including, among others, the following:

•operator error and breakdown or failure of equipment or processes;

•operating limitations that may be imposed by environmental or other regulatory requirements;

•labor disputes;

•problems resulting from an aging workforce and retirements;

•ability to maintain and retain a knowledgeable workforce;

•availability and cost of fuel;

•fuel supply interruptions, including transportation interruptions;

•availability and cost of water;

•water supply interruptions;

•catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences; and

•compliance with mandatory reliability standards when such standards are adopted and as subsequently revised.

Unforeseen outages at our generating facilities could lead to higher costs because we may be required to purchase power in volatile electric power markets. A decrease or elimination of revenues from electric power produced by our generating facilities or an increase in the cost of operating the facilities could adversely affect our results of operation.

If we are unable to protect our information systems against service interruption, misappropriation of data or breaches of security, our operations could be disrupted and our financial condition could be adversely affected.

We operate in a highly regulated industry that requires the continued operation of advanced information technology systems and network infrastructure. We rely on networks, information systems and other technology, including the Internet and third party hosted servers, to support a variety of business processes and activities. We use information systems to process financial information and results of operations for internal reporting purposes and to comply with regulatory financial reporting, legal and tax requirements. Our generation and transmission assets and information technology systems, or those of our co owned plants, could be directly or indirectly affected by deliberate or unintentional cyber incidents. Our industry has begun to see an increased volume and sophistication of cyber incidents. These incidents may be caused by failures during routine operations such as system upgrades or user errors, as well as network or hardware failures, malicious or disruptive software, computer hackers, rogue employees or contractors, cyber attacks by criminal groups or activist organizations, geopolitical events, natural disasters, failures or impairments of telecommunications networks, or other catastrophic events. In addition, such incidents could result in unauthorized disclosure of material confidential information, including personally identifiable information. While there have been immaterial incidents of phishing and attempted financial fraud across our system, there has been no material impact on business or operations from these attacks. However, we cannot guarantee that security efforts will prevent breaches, operational incidents, or other breakdowns of information technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.

In addition, in the ordinary course of business, we collect and retain sensitive information, including personally identifiable information about employees, directors, and other third parties, and other confidential information. In some cases, administration of certain functions may be outsourced to third-party service providers that could also be targets of cyber attacks.

If our technology systems are breached or otherwise fail, we may be unable to fulfill critical business functions, including the operation of our generation and transmission assets and our ability to effectively maintain certain internal controls over financial reporting. Further, our generation assets rely on an integrated transmission system, a disruption of which could negatively impact our ability to deliver power to our Members. A major cyber incident could result in significant business disruption, compromised or improper disclosure of data, and expenses to repair security breaches or system damage and could lead to litigation, regulatory action, including penalties or fines, and an adverse effect on our financial condition, results of operations, and reputation. Moreover, the amount and scope of insurance maintained against losses resulting from any such cyber incident may not be sufficient to cover losses or otherwise adequately

compensate for any disruptions to business that could result. In addition, as cybercriminals become more sophisticated, the cost of proactive defensive measures may increase. We also may have future compliance obligations related to new mandatory and enforceable NERC reliability standards addressing the impacts of geomagnetic disturbances and other physical security risks to the reliable operation of the bulk power system.

We may not be able to obtain an adequate supply of fuel which could limit our ability to operate our facilities.

We obtain our fuel supplies, including coal, natural gas and oil, from a number of different suppliers, including mines in which we have ownership interests. Any disruptions in our fuel supplies, including disruptions due to weather, labor relations, permitting, regulatory matters, and environmental regulations, or other factors affecting our coal mines or fuel suppliers, could result in us having insufficient levels of fuel supplies. For example, rail transportation bottlenecks have from time to time caused transportation companies to be unable to perform their contractual obligations to deliver coal on a timely basis and have resulted in lower than normal coal inventories at certain of our generating facilities. Similar inventory shortages could occur in the future due to any of the disruptions described above. In addition, if challenges to the permit for the Collom pit at the Colowyo Mine affect the operation of the Collom pit, it may affect our inventory of fuel supplies. Natural gas and oil supplies can also be subject to disruption due to natural disasters and similar events. Any failure to maintain an adequate inventory of fuel supplies could require us to operate other generating facilities at higher cost or pay significantly higher prices to obtain electric power from other sources, which would have an adverse effect on our results of operations.

We may be held liable for the actions or omissions of our members, despite the fact that we and our members are separate legal entities and we do not own, operate, control or have the right to control our members.

Litigation seeking to impose liability on us for the actions of our Members has increased. The plaintiffs in these actions have claimed that we are jointly liable for the actions of our Members, including under theories of partnership, joint venture, joint/common enterprise, or alter ego. The plaintiffs in these actions have also claimed that we owe them independent duties regarding our Members. We strongly dispute these claims as inconsistent with the facts and law. Although a jury determined in one case that we and one of our Members do not operate as a joint venture or joint enterprise, the jury determined we violated an independent duty owed to the plaintiffs and were 20 percent at fault as a result of the Member’s independent actions. There can be no assurance that a court or jury will determine in the future that we are not severally liable or jointly liable for the actions of our members. Our results of operations and financial condition could be adversely affected if courts or juries determine we are severally or jointly liable for the actions of our members.

Losses from wildfires could adversely affect our financial condition, future results of operations, and cash flow.

We have ownership or capacity interests in approximately 5,671 miles of high voltage transmission lines, including transmission lines that cross through forest areas and grasslands.  Certain of our transmission facilities are located on federal land and certain permits with the federal government impose strict liability on us up to a maximum cap related to our transmission facilities. If a wildfire involving our transmission facilities were to occur, we could be liable for property damage and other costs, which liability could be substantial and in excess of our liability insurance.  Any such liability could materially affect us and our financial condition, future results of operations, and cash flow.

We rely on purchases of electric power from other power suppliers and long term contracts to purchase and transport fuels and to sell electricity we generate, which exposes us to market and counterparty risks.

Our electric power supply strategy relies, in part, on purchases of electric power from other power suppliers. In 2019, purchased power provided 38.5 percent of our energy requirements. We expect the amount of energy we purchase to increase in the future with the closures of our coal-fired base load facilities and the increasing amount of renewable power purchase contracts. These purchases consist of a combination of purchases under long term contracts and short-term market purchases of electric power. We also rely on long term contracts with third parties to (a) manage our supply and transportation of fuel for our generating facilities, and (b) sell electricity we generate to non-member utilities. We are exposed to the risk that counterparties to these long term contracts will breach their obligations to us or claim that we are in breach. We are also exposed to the risk that counterparties to our renewable power purchase contracts will be unable

to construct the renewable generating facilities by the time period specified in the respective contract or at all. If this occurs, we may be forced to enter into alternative contractual arrangements or enter into short-term market transactions at then current market prices. Purchasing electric power in the market exposes us, and consequently our Members, to market price risk because electric power prices can fluctuate substantially over short periods of time. The terms of these new arrangements may be less favorable than the terms of our current agreements, which could have an adverse effect on our results of operations.

When we enter into long term electric power purchase contracts, we rely on models based on our judgments and assumptions of factors such as future demand for electric power, future market prices of electric power and the future price of commodities used to generate electricity. These judgments and assumptions may prove to be incorrect. As a result, we may be obligated to purchase electric power under long term agreements at a price which is higher than we could have obtained in alternative short term arrangements. Conversely, our reliance on short-term market purchases exposes us to increases in electric power prices.

Our long term power purchase contracts include contracts with WAPA and Basin, consisting of 14.2 percent and 13.4 percent, respectively, of our Member sales in 2019. We experience favorable pricing terms under our WAPA contracts under federal laws that give preference to federal hydropower production to certain customers, including cooperatives. If the federal laws under which we receive favorable pricing were to be amended or eliminated or if WAPA were to no longer provide us with favorable pricing for any other reason, we would have to pay significantly higher prices to obtain this electric power, which could have an adverse effect on our results of operations. The prices we pay for power under the WAPA and Basin contracts are determined by WAPA and Basin, respectively, and are subject to change in accordance with the terms of the contracts. If we would have to pay significantly higher prices under these contracts, it could have an adverse effect on our results of operations.

A portion of our workforce is represented by unions. Failure to successfully negotiate collective bargaining agreements, or strikes or work stoppages, could cause our business to suffer.

Many of our employees are covered by collective bargaining agreements, and other employees may seek to be covered by collective bargaining agreements. Strikes or work stoppages or other business interruptions could occur if we are unable to renew these agreements on satisfactory terms or enter into new agreements on satisfactory terms or if we are unable to otherwise manage changes in, or that affect, our workforce, which could adversely impact our business, financial condition or results of operations. The terms and conditions of existing, renegotiated or new collective bargaining agreements could also increase our costs or otherwise affect our ability to fully implement future operational changes to enhance our efficiency or to adapt to changing business needs or strategy.

We may be subject to physical attacks.

As operators of energy infrastructure, we may face a heightened risk of physical attacks on our electric systems. Our generation and transmission assets and systems are geographically dispersed and are often in rural or sparsely populated areas which make them especially difficult to adequately detect, defend from, and respond to such attacks.

If, despite our security measures, a significant physical attack occurred, we could have our operations disrupted, property damaged, experience loss of revenues, response costs, and other financial loss; and be subject to increased regulation, litigation, and damage to our reputation, any of which could have a negative impact on our business and results of operations.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 2.PROPERTIES

Generating Facilities

We own, lease, have undivided percentage interests in, or have tolling arrangements with respect to, various generating facilities which are identified in the table below. All of our interests in these facilities or agreements, as applicable, are subject to the lien of our Master Indenture.

*The Unit Ratings for each generating facility are subject to fluctuations to account for various operating conditions and environmental mitigation equipment requirements.

Craig Generating Station.  Craig Station is a three‑unit, 1,285 MW coal‑fired electric generating facility located near Craig, Colorado. Craig Station Units 1 and 2 and related common facilities are known as the Yampa Project and jointly owned as tenants in common by us and four other regional utilities pursuant to a participation agreement. We own a 24 percent interest in Craig Station Units 1 and 2, which each have capacity of 427 MWs and 410 MWs, respectively, and a 100 percent interest in Craig Station Unit 3, which has a capacity of 448 MWs. We are the operating agent for all three units and are responsible for the daily management, administration and maintenance of the facility. The costs associated with operating Craig Station Units 1 and 2 are divided on a pro‑rata basis among all the participants. Our total share of Craig Station’s capacity is 648 MWs. On September 1, 2016, we announced that the owners of Craig Station Unit 1 reached an agreement whereby Unit 1 is intended to be retired by December 31, 2025. On January 9, 2020, we announced that our Board approved the early retirement of Craig Station Units 2 and 3 by 2030.

Escalante Generating Station.  Escalante Station is a 253 MW coal‑fired electric generating facility located near Prewitt, New Mexico. Escalante Station is wholly owned and operated by us. On January 9, 2020, we announced that our Board approved the early retirement of Escalante Station by the end of 2020.

Laramie River Generating Station.  Laramie River Generating Station is a three-unit, 1,710 MW coal‑fired electric generating facility located near Wheatland, Wyoming and operated by Basin. Laramie River Generating Station and related transmission lines are known as the MBPP, and jointly owned as tenants in common by us and four other regional utilities pursuant to a participation agreement. We own a 27.1 percent interest in the total capacity of the facility. Certain costs associated with operating the facility are divided on a pro‑rata basis among the participants, while other costs are shared in proportion to the generation scheduled and energy produced for each participant. Laramie River Generating Station Unit 1 is connected to the Eastern Interconnection, while Units 2 and 3 are connected to the Western

Interconnection. Our share of Laramie River Generating Station’s total capacity is 464 MWs, which we receive out of Units 2 and 3.

Springerville Generating Station Unit 3.  Springerville Unit 3, located in east‑central Arizona, is a 417 MW unit that is part of a four-unit, 1,578 MW coal‑fired electric generating facility operated by TEP. Under contractual agreements, we, as the lessee of Springerville Unit 3, are taking 417 MWs of capacity from the unit and selling 100 MWs of such capacity to Salt River Project and 100 MWs of such capacity to PNM. We own a 51 percent equity interest (including the 1 percent general partner equity interest) in Springerville Partnership, which owns Springerville Unit 3. Our leasehold interest, as the lessee of Springerville Unit 3, is subject to the lien of our Master Indenture, but Springerville Unit 3 is not subject to the lien of our Master Indenture. Springerville Unit 3 is subject to a mortgage and lien to secure the Springerville certificates.

Burlington Generating Station.  Burlington Generating Station consists of two 55 MW simple-cycle combustion turbines that operate on fuel oil and is located in Burlington, Colorado. The units are primarily operated during periods of peak demand. Burlington Generating Station is wholly owned and operated by us.

J.M. Shafer Generating Station.  J.M. Shafer Generating Station is a 272 MW, natural gas fired, combined-cycle generating facility located near Fort Lupton, Colorado, which is primarily operated to provide intermediate load generating capacity. J.M. Shafer Generating Station is owned by our wholly‑owned subsidiary TCP. 122 MWs was sold to PSCO under a tolling agreement that expired in June 2019. After expiration of such PSCO tolling agreement, we utilize the entire 272 MWs of output under a tolling arrangement with TCP. Our interest in J.M. Shafer Generating Station is not subject to the lien of our Master Indenture, but our interest in the tolling arrangement with TCP is subject to the lien of our Master Indenture.

Knutson Generating Station.  Knutson Generating Station consists of two 70 MW simple-cycle combustion turbines that can operate on either natural gas or fuel oil and is located near Brighton, Colorado. The units are primarily operated during periods of peak demand. Knutson Generating Station is wholly owned and operated by us.

Limon Generating Station.  Limon Generating Station consists of two 70 MW simple-cycle combustion turbines that can operate on either natural gas or fuel oil and is located near Limon, Colorado. The units are primarily operated during periods of peak demand. Limon Generating Station is wholly owned and operated by us.

Pyramid Generating Station.  Pyramid Generating Station consists of four 40 MW simple-cycle combustion turbines that can operate on either natural gas or fuel oil and is located near Lordsburg, New Mexico. The units are primarily operated during periods of peak demand. Pyramid Generating Station is wholly owned and operated by us.

Rifle Generating Station.  Rifle Generating Station is an 81 MW, natural gas fired, combined-cycle generating facility located near Rifle, Colorado, which is primarily operated during periods of peak demand. Rifle Generating Station is wholly owned and operated by us.

Transmission

As of December 31, 2019, we own, lease, or have undivided percentage interest in transmission lines as described in the following table (estimated miles based on Geographic Information System):

We are an ownership participant in the MBPP (Laramie River Generating Station) and Yampa Project (Craig Station Units 1 and 2) transmission systems and have ownership interests or capacity rights in several other transmission line participation projects. Transmission investment also includes ownership or major equipment ownership in approximately 407 substations and switchyards. All of our interests in these facilities or agreements, as applicable, are subject to the lien of our Master Indenture.

Coal Mines

We, through either our subsidiaries or our membership in third parties, have an ownership interest in the coal mines identified in the table below.

ITEM 3.LEGAL PROCEEDINGS

LPEA and United.  Pursuant to our Bylaws, a 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 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 Members with withdrawal numbers is unlawful. LPEA seeks the COPUC to issue an order related to our temporary suspension and for the COPUC to establish the withdrawal number. On November 6, 2019, United filed a formal complaint with the COPUC, alleging that we have hindered United’s ability to explore its power supply options by either withdrawing from us or continuing as a member under a partial requirements contract. United alleges, among other things, that we have failed to provide a just, reasonable, and non-discriminatory withdrawal number. United seeks for the COPUC to issue an order establishing a withdrawal number. LPEA and United constitute approximately 5.6 percent and 16.6 percent, respectively, of our Member revenue in 2019. On November 20, 2019, the COPUC consolidated the two proceeding into one, 19F-0621E, and provided that the consolidated proceeding shall be heard before one hearing commissioner. On December 23, 2019, we filed a motion to stay the schedule in the proceeding pending the FERC’s decision on our Petition for Declaratory Order filed with FERC regarding the COPUC’s jurisdiction over us, including our Members’ early termination of obligations under wholesale electric service contracts with us and withdrawal from membership in us. LPEA and United filed their direct testimony on January 10, 2020 and we filed our answer testimony on February 12, 2020. A number of interventions have been filed by our Members, including Members from each of our four states.  By interim decision of the hearing commissioner on January 30, 2020, all motions to intervene were denied. A number of Members filed motions contesting the interim decision denying the interventions, which motions were denied by the hearing commissioner.  On February 12, 2020, by

interim decision of the hearing commissioner, the hearing commissioner denied our December 23, 2019 motion to stay the proceeding and determined that the COPUC has jurisdiction over the complaints of United and LPEA and the complaints are ripe for review by the COPUC. On February 26, 2020, we filed our answers to the formal complaints filed by LPEA and United. A five-day evidentiary hearing is scheduled to begin on March 23, 2020.

FERC Tariff and Declaratory Order.   Because of increased pressure by the states to regulate our rates and charges, through the addition of a non-cooperative member in 2019 and specifically by the addition of MIECO, Inc. as a member on September 3, 2019, we became FERC jurisdictional for our Member rates, transmission service, and our market based rates. We filed our tariff for wholesale electric service and transmission at FERC on December 23, 2019. We filed our tariffs for wholesale electric service and transmission at FERC in stages between December 23 and 27, 2019, with supplemental filings completed by December 30, 2019. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. Nine parties have filed protests, including five Members. Nine interventions have been filed including four Members intervening in support. In addition, on December 23, 2019, we filed our Petition for Declaratory Order 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. Thirteen parties filed interventions and/or protests, including seven by Members, four in support, two in protest, and one taking no position. A number of comments in support have been filed with FERC, including supporting comments from three Members. Some of the interveners and protestors in both our tariff filing and our Petition for Declaratory Order, including some of our Members and the COPUC, are alleging that we are not a FERC‑jurisdictional public utility and are still exempt from FERC wholesale rate regulation pursuant to the FPA.  Until we made our reapplication in December 2019, we were a FERC-jurisdictional public utility making sales and providing services without satisfying the FPA’s filing obligations and FERC’s prior notice requirements. FERC may require us to refund to our customers certain amounts collected for the entire period that the rate was collected without FERC’s authorization, including Member and non-member electric sales and wheeling revenue. FERC may also impose civil penalties for the time period between when we became a FERC-jurisdictional public utility and when we made our reapplication in December 2019. Furthermore, current practices including our use of regulatory assets are subject to FERC approval and subject to change as a result. It is not possible to predict if FERC will require us to refund amounts to our customers, if FERC will impose civil penalties, if FERC will approve our current practices regarding use of regulatory assets, or to estimate any liability associated with this matter. We cannot predict the outcome of our tariff filings or our Petition for Declaratory Order, but expect FERC to rule on our tariff filings by the end of March 2020.

FERC Fixed Cost Recovery Petition.    On February 17, 2016, we filed a Petition for Declaratory Order with FERC seeking a declaratory order from FERC finding that the fixed cost recovery mechanism in our revised Board policy is consistent with the provisions of PURPA and the implementing regulations of FERC. The revised Board policy provides for recovery of the unrecovered fixed costs directly from a Member as a result of that Member purchasing power from a “qualifying facility” in an amount that causes it to exceed the 5 percent limitation on that Member’s self-supply of power pursuant to its wholesale electric service contract, rather than allocating the costs among all of our Members. The fixed cost recovery is calculated based on the difference between our wholesale rate to our Members and our avoided costs. Various individuals and entities filed comments and four entities filed motions to intervene, including our Member, DMEA. On June 16, 2016, FERC denied our Petition for Declaratory Order related to the fixed cost recovery mechanism in our revised Board policy. On July 18, 2016, we filed a Request for Rehearing with FERC regarding FERC’s June 16 order. In addition, five other generation and transmission cooperatives filed a Request for Rehearing with FERC. We cannot predict the outcome of our July 18 request for rehearing filed with FERC.

NMPRC Proceeding.  On October 19, 2012, we gave notice, as required by New Mexico law, to the NMPRC of our A‑37 wholesale rate which was scheduled to become effective on January 1, 2013. The rate would have increased revenue collected from all of our Members. In November 2012, three of our Members located in New Mexico filed protests of our rates with the NMPRC. On December 20, 2012, the NMPRC suspended the rate filing in New Mexico. On January 25, 2013, we filed a Complaint for Declaratory and Injunctive Relief in the Federal District Court in New Mexico asking the Court to declare the actions of the NMPRC to be in violation of the Commerce Clause of the United States Constitution. On September 10, 2013, we gave notice, as required by New Mexico law, to the NMPRC of our A‑38 wholesale rate which was scheduled to become effective on January 1, 2014. Four Members filed protests with the NMPRC challenging the A-38 rate. The A‑38 rate modified the rate design but did not increase the general revenue requirement. On December 11, 2013, the NMPRC suspended the A‑38 rate filing. In August 2014, we and the New

Mexico Members executed a preliminary mediation agreement providing for a temporary rate rider through no later than December 31, 2015, and a suspension of the procedural schedule related to the rate protest to allow the parties time to proceed with more extensive discussions on a global settlement. In October 2015, the Federal District Court in New Mexico temporarily stayed the federal proceeding to allow the parties’ time to negotiate a global settlement. No initial scheduling conference in the federal proceeding has been scheduled and the parties periodically file status reports with the Court. On December 9, 2015, we and the New Mexico Members filed a joint motion with the NMPRC seeking continuation of the suspension of the procedural schedule related to the rate protests to allow the parties additional time to proceed with further negotiations towards a global settlement. On January 6, 2016, the NMPRC ordered that the procedural schedule related to the rate protests remains suspended until further order of the NMPRC. As part of the global settlement, the parties seek to address the issue of our rate regulation in New Mexico, payment of capital credits, and whether we have the right to collect the amounts uncollected from our New Mexico Members as a result of the suspension of prior rate filings. We cannot predict the outcome of this matter or if a global settlement will be reached, although we do not believe this proceeding is likely to have a material adverse effect on our financial condition or our future results of operations or cash flows.

Water Proceedings.  We are involved in a water rights proceeding in the State of New Mexico that could impact the water rights for Escalante Station. It is an adjudication of water rights associated with the Bluewater Toltec Area to determine the past, present and future use of water rights of the Pueblos of Acoma and Laguna. We cannot predict the outcome of this matter, although we do not believe this proceeding is likely to have a material adverse effect on our financial condition or our future results of operations. See “BUSINESS — POWER SUPPLY RESOURCES — Water Supply.”

ITEM 4.MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S‑K (17 CFR 229.104) is included in Exhibit 95 to this annual report on Form 10‑K.

PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not Applicable.

ITEM 6.SELECTED FINANCIAL DATA

The following tables set forth our selected consolidated financial data as of the dates for the years indicated. This consolidated financial data is qualified in its entirety by and should be read in conjunction with the more detailed information and the audited financial statements, including the notes to such financial statements, and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7.