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 period ended December 31, 2015

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. 333-203560

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:  NONE

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ☒ Yes  ☐ No

Indicate by check mark if disclosure of delinquent filer pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, the best of the Registrant’s knowledge, if definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K.  ☒

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of ‘‘large accelerated filer,’’ ‘‘accelerated filer,’’ and ‘‘smaller reporting company’’ in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer ☐  Accelerated Filer ☐  Non-Accelerated Filer ☒ Smaller Reporting Company ☐

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 AND TRANSMISSION ASSOCIATION, INC.

Index to 2015 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 or operation of facilities (often, but not always, identified through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “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 major parts 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 Members, which, in turn, supply retail electric power to residential, commercial, industrial and agricultural customers in a service area with a population of approximately 1.5 million people.

We are owned entirely by our 44 Members.  Forty of our Members are not‑for‑profit, electric distribution cooperative associations.  The remaining four Members are public power districts, which are political subdivisions of the State of Nebraska.  The retail service territory of our Members covers approximately 200,000 square miles and their customers include rural residences, farms and ranches, and large and small businesses and industries.  Our Members are the sole state certified providers of electric service to retail (residential and business) customers within their designated service territories.

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.tristategt.org.  Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on 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, 2015, we employed 1,561 people, of which approximately 361 were subject to collective bargaining agreements.  As of the date of this annual report on Form 10-K, none of these collective bargaining agreements will expire within one year.

Cooperative Structure

A cooperative is a business entity owned by its members, which are also its retail or wholesale customers.  Cooperatives are designed to give their members the opportunity to satisfy their collective needs in a particular area of business more effectively than if the members acted independently.  As organizations acting on a not‑for‑profit basis, cooperatives provide 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‑of‑service and to collect a portion of revenues in excess of expenses, which constitutes margins.  Margins not 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 and the cooperative’s loan and security agreements.

Electric cooperatives generally include distribution cooperatives, such as the majority of our Members, and generation and transmission cooperatives, such as us.  The primary purpose of electric distribution cooperatives is to supply the requirements of their retail consumers through bulk purchases of capacity and energy and to maintain a distribution system to deliver the electricity necessary to satisfy their consumers’ requirements.  The primary purpose of generation and transmission cooperatives is to provide wholesale electric power to their member distribution cooperatives.

Power Supply and Transmission

We supply and transmit our Members’ electric power requirements through a portfolio of resources, including generating facilities, long‑term purchase contracts and forward, short‑term and spot market energy purchases.  We own, lease, have undivided percentage interests in, or have tolling arrangements with respect to, various generating facilities.  These generating facilities provide us with maximum available power of 2,841 MWs, including 1,874 MWs from coal‑fired base load facilities and 967 MWs from gas/oil‑fired facilities.  We purchase hydroelectric power under long‑term purchase contracts which provide us with maximum available power of 583 MWs during the summer and 536 MWs during the winter.  We purchase additional power on a long and short‑term basis, including 249 MWs from other renewable energy resources, including wind, solar and small hydro.  In 2015, we executed a 76 MW wind‑based power purchase agreement and 55 MWs of solar‑based power purchases agreements that are expected to achieve commercial operation in 2016 and 2017.  Additionally, 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 5,560 miles of high‑voltage transmission lines and own or have major equipment ownership in approximately 357 substations and switchyards.  See “PROPERTIES” for a description of our generation and transmission facilities.

Depending on our system requirements and contractual obligations, we are likely to both purchase and sell electric power during the same fiscal period.  In addition, 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 spot market purchases during periods of generation outages at our facilities.  See “— POWER SUPPLY RESOURCES — Purchased Power.”

MEMBERS

General

Our Members provide electric services, consisting of power supply and distribution services, to residential, commercial, industrial and agribusiness customers 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.  Our Members and their locations are as follows:

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 constitute approximately 95 percent of our revenue from Member sales in 2015) and extending through 2040 for the remaining two Members (Kit Carson Electric Cooperative, Inc. and Delta Montrose Electric Association which constitute approximately 5 percent of our revenue from Member sales in 2015), and 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 our Members, and obligates our Members to purchase and receive from us at least 95 percent of the power they require for the operation of their systems, except for sources, such as photovoltaic cells, fuel cells, or others that are not connected to such Member’s distribution or transmission system.  Our Members may elect to provide up to 5 percent of their requirements from distributed or renewable generation owned or controlled by them.  As of December 31, 2015, 16 Members have enrolled in this program with capacity totaling approximately 79 MWs.

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).  The following table shows our Members’ aggregate coincident peak demand for the years 2011 through 2015 and the amount of energy that we supplied them:

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 the policy and procedures 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, Inc., was 13.1 percent of our Member revenue and 11 percent of our overall revenue, in 2015.  No other Member exceeded 10 percent of our Member revenue or our overall revenue in 2015.  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.

Our Members do not have a unilateral right to exit their membership in us.  Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as the 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.

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 territory extends throughout the state and encompasses suburban, rural, industrial, agricultural and mining areas.  In Nebraska, our Members’ service territory is comprised primarily of rural residential and farm customers in the western portion of the state.  In Wyoming, our Members’ service territory extends from the north central to the southeastern portion of the state and encompasses rural residential, agricultural and mining areas.  In New Mexico, our Members’ service territory extends throughout the northern, southern, central and western parts of the state, serving agricultural, rural residential, suburban, small commercial and mining customers.  The diversity in customer bases, economic sectors, climate and weather patterns of the service territories creates balance within our system.

Customers.  Our Members’ sales of energy in 2014 (which is the most recent information available to us) were divided by customer class as follows:

From 2009 to 2014, our Members experienced an average annual compound growth rate of approximately 0.6 percent in the number of customers and an average annual compound growth rate of 1.9 percent in energy sales.  In 2014, which is the most recent year with data available to us, the 15 largest customers of our Members represented 18.8 percent of electric energy sales by our Members, although no single customer of our Members represented more than 5 percent of our total energy sales.  These customers are primarily in the minerals extraction and transportation business, including natural gas, carbon dioxide and oil production.

Our Members’ average number of customers per mile of energized line has been stable since 2008 at approximately five customers per mile.  System densities of our Members in 2014 ranged from 1.2 customers per mile to 12.5 customers per mile.

Relationship with Members

Our Members operate their systems on a not‑for‑profit basis.  We are a membership corporation, and our Members are not our subsidiaries.  Except with respect to the obligations of our Members under their respective wholesale electric service contracts or other agreements with us, we have no legal interest in, or obligation with respect to, any of the assets, liabilities, equity, revenue or margins of our Members, other than our rights under such wholesale electric service contracts.  The revenues of our Members are not pledged to us, but are received by the respective Member and are the source from which moneys are derived by such Member to pay for capacity and energy supplied by us under the respective wholesale electric service contracts as well as from others.  We occasionally have disputes with individual Members or small groups of Members, generally relating to our rates.  See “LEGAL PROCEEDINGS.”

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, but the prospect of such legislation has diminished due to a variety of factors, including the risks associated with retail competition, the state of the economy, and commodity prices.

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 territory that provides, among other things, that each of PSCO, PacifiCorp and Tri‑State will:

RATE REGULATION

General

We provide electric power to our Members at rates established by our Board.  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.  Although our rates are generally not subject to regulation by federal, state or other governmental agencies, we are required to submit the rates to the NMPRC.  We provide electric power to non‑members at contractual rates under long‑term arrangements and at market prices in spot sale transactions.  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.  This policy was last revised in May 2015.  The policy may be changed by our Board at any time.  Our Master Indenture requires us to establish rates 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 14 percent in 2015 and 18 percent thereafter.

Our electric sales revenues are derived from electric power sales to our Members and non‑member purchasers.  Rates for electric power sales to our Members consist of two billing components: an energy rate and a demand rate.  Member rates for energy and demand are set by our Board, consistent with adequate electrical reliability and sound fiscal policy.  Energy is the physical electricity delivered through our transmission system to our Members.  Approved by our Board in September 2015 and effective January 1, 2016, our 2016 wholesale rate (A‑39 rate) has an energy rate billed based upon a price per kWh of energy delivered and a demand rate billed 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 Friday, with the exception of six holidays.  In 2015 and 2014, our wholesale rate (A‑38 rate) had a different rate design that incorporated seasonal average demand rates.  The monthly average demand was calculated by dividing each Member’s total monthly energy (kWh) usage by the total hours in the month.  The A‑38 rate design also had an energy rate that incorporated an on-peak and off-peak period.  We developed demand response and energy shaping products to compliment the A‑38 rate schedule.  The participating Member’s monthly statements were adjusted using the demand response and energy shaping product incentives for Members utilizing those products.  In November 2014, we implemented an optional rate (TR‑1) available to our non-New Mexico Members, effective December 1, 2014 through December 31, 2015.  The TR‑1 optional rate had an energy rate billed based upon a price per kWh of energy delivered and a demand rate based upon our Member’s highest thirty-minute integrated total demand measured using the Member’s coincident peak during our peak period in each monthly billing period during our summer peak period or the winter peak period.  Three Members elected this TR-1 optional rate.  In 2013, our A-37 rate design was in effect.  The A‑37 rate design had slightly lower seasonal average demand rates compared to our A‑38 rate.  In 2012, our wholesale rate schedule (A‑36 rate) had an energy rate billed based upon a price per kWh, of energy delivered and a demand rate based upon our Member’s highest thirty-minute integrated total demand measured using actual metered kilowatt usage in each monthly billing period during our summer peak period or our winter peak period.

Rate Policy

Pursuant to our Board Policy for Financial Goals and Capital Credits, as described above, 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 following table shows our average Member cents/kWh sales for the years 2011 through 2015.  The average Member cents/kWh sales is our total Members electric sales revenue, including for energy, demand, and transmission, in a given year divided by the total kilowatt hours sold to the Members in that given year.

Under the Master Indenture, we are required to establish rates that are reasonably expected to achieve a DSR of at least 1.10 on an annual basis.  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.

Regulation of Rates

Our rates are established by our Board.  However, we are involved in a proceeding in New Mexico which could result in oversight of our prior wholesale rates by the NMPRC.  This proceeding is currently suspended for global settlement discussions regarding our prior A-37 (2013) and A-38 (2014 and 2015) wholesale rates payable by our Members.  According to New Mexico law, we are required to file our Member rates with the NMPRC and the NMPRC only has regulatory authority over our rates in the event three or more of our New Mexico Members file a request to review our rates and the NMPRC finds such request to be qualified.  See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Factors Affecting Results — Rates and Regulations.”  Electric cooperatives are not subject to rate regulation by FERC, under the FPA, if they are financed by RUS; they sell less than 4 million MWhs of electricity per year; or they are wholly owned by entities that are themselves not subject to rate regulation by FERC.  We are not subject to FERC rate jurisdiction since each of our Members sells fewer than 4 million MWhs per year.  In 2014, which is the most recent year with data available to us, our largest Member sold 1.6 million MWhs.

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 2015, 63 percent of our energy resources were provided by our generation and 37 percent by purchased power.

Generating Facilities

We own, lease, have undivided percentage interests in, or have tolling arrangements with respect to, various generating facilities.  These generating facilities provide us with maximum available power of 2,841 MWs, including 1,874 MWs from coal‑fired base load facilities and 967 MWs from gas/oil‑fired facilities.  See “PROPERTIES” for a description of our various generating facilities.

Purchased Power

We supplement our capacity and energy requirements not supplied by our generating facilities through long‑term purchase contracts, and forward, short‑term and spot market energy purchases.

Our principal long‑term power purchase contracts are with WAPA and Basin.  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 and municipal electric systems and certain other “preference” customers.  WAPA markets and transmits the power to us under three contracts, one relating to WAPA’s Loveland Area Project (which terminates September 30, 2024), and two contracts relating to WAPA’s Salt Lake City Area Integrated Projects (which terminate September 30, 2024).  In January 2015, we entered into a new contract with WAPA relating to the Loveland Area Project which commences upon termination of the above referenced contract terminating September 30, 2024, and will run through September 2054.  We also expect to enter into two new contracts related to Salt Lake City Area Integrated Projects which will extend the term of those existing contracts.  The Loveland Area Project generally consists of generation and transmission facilities located in the Missouri River Basin.  The Salt Lake City Area Integrated Projects consists of generation and transmission facilities located in the Colorado River Basin.  The following table shows the maximum power available from these WAPA resources in the winter season (October‑March) and the summer season

(April‑September):

We utilize a portion of our purchases from Basin to supply power to our Nebraska Members, which are primarily located east of the electrical grid separation and are generally isolated from our generating facilities that are located west of the separation.  We have a contract with Basin for a term ending December 31, 2050, to supply the electrical requirements of our Nebraska Members in excess of power supplied by WAPA.  As of December 31, 2015, the approximate Nebraska Members’ need from this resource was 314 MWs.  We also purchase 225 MWs from Basin for use west of the electrical separation under a contract for a term ending in 2050.

In addition to long‑term power purchase contracts, we purchase power on the open market.  We utilize market purchases 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 utilize spot market purchases during periods of generation outages.  However, in order to minimize our exposure to such spot market purchases, our power supply arrangements with PSCO and the Salt River Project provide that our obligation to supply power may be reduced in proportion to a decrease in our power supply resources.  In addition, we have hazard sharing arrangements with Colorado Springs Utilities, Platte River Power Authority, and TEP, which provide for supply of power to us in the event of forced outages at specified generation facilities.

Renewable Power Purchases

In addition to our contracts with WAPA for hydroelectric power purchases, we have entered into various renewable power purchase contracts, the largest of which are summarized in the table below.

(2)Anticipated Year of Contract Expiration based upon anticipated Year of Commercial Operation

Other Generation Development

We continuously evaluate potential resources required to serve the long‑term requirements of our Members.  Over the past several years, in a joint effort with Sunflower, a Kansas generation and transmission cooperative, and others, we have 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.  Through December 2015, we have incurred development costs of approximately $94 million, including the purchase of certain water rights and real estate interests, in connection with the Holcomb development.  There have been several legal challenges to the development of Holcomb, including challenges to the Prevention of Significant Deterioration Permit and to the effectiveness of RUS consents to Sunflower’s development contracts with us.  We, along with Sunflower, continue to

work on the legal challenges to the Prevention of Significant Deterioration Permit.  However, our Board has not yet made a decision to proceed with construction of the project including us exercising our option to acquire the development rights.  We have also acquired real estate interests and water rights for the Colorado Power Project located near Holly, Colorado.  Through December 2015, we have incurred development costs of approximately $71 million, including 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 a Prevention of Significant Deterioration Permit for this development.

Power Sale Contracts

We have entered into various power sales contracts with other utilities, the largest of which are discussed below.  We have two existing agreements with PSCO for the sale of contingent power.  The agreements are on substantially similar terms.  Under the first agreement, we have agreed to supply to PSCO 100 MWs of capacity through March 2017.  Under the second agreement, we have agreed to supply to PSCO on an annual basis through March 2016, 25 MWs of power from April through September and 75 MWs of power from October through March.  These contracts are contingent upon the availability of capacity from Craig Station Units 1, 2, and 3, and Laramie River Generating Station Units 2 and 3.  We also have two agreements with PSCO for the output of the two gas turbines at Knutson Generating Station and one gas turbine at the Limon Generating Station for a total of 210 MWs in tolling capacity sales that expire in April 2016.  We do not expect these four agreements discussed above with PSCO to be renewed.  Additionally, we, through one of our wholly‑owned subsidiaries, have an agreement with PSCO to sell 122 MWs in tolling capacity from the J.M. Shafer Generating Station that expires in June 2019.  We also have an agreement with Salt River Project to provide 100 MWs of power contingent on the operation of Springerville Unit 3 that expires in August 2036.

Fuel Supply

Coal.    We purchase coal under long‑term contracts and in spot market transactions.  The long‑term arrangements provide price stability and the spot market transactions provide the flexibility to purchase coal when it is economically attractive to do so.  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‑based generating facilities:

(1)San Juan Generating Station Unit 3 is expected to be retired by December 31, 2017

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, we have obligations for certain reclamation activities mandated by state and federal laws.  These liabilities are recognized and recorded on our financial statements when required by accounting guidelines.

Natural Gas.  The majority of the natural gas we purchase is for facilities used primarily to fill peak demands.  We currently enter into fixed‑price, fixed‑quantity physical contracts for a portion of our anticipated needs, and purchase

the remainder of our needs on the spot market.  The majority of natural gas is purchased in the Cheyenne Hub area, which is in close proximity to the natural gas generation facilities we tend to utilize most frequently.  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 Rockies, we presently anticipate that sufficient supplies of natural gas will be available in the foreseeable future.  We have several long‑term natural gas transportation contracts that provide firm rights to move natural gas from various receipt points to our facilities.  Finally, we may utilize financial instruments to price hedge our forecasted forward 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.  The table below provides an overview of our water supply arrangements.  Our generating facilities, however, are located in the West where demand for available water supplies is heavy, particularly in drought conditions.  Litigation and disputes over water supplies are common and often protracted, which can lead to uncertainty regarding any user’s rights to available water supplies.  If we are 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 two separate water rights proceedings in the State of New Mexico that could impact the water rights for Escalante Station.  The first proceeding is an adjudication of water rights associated with 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 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 availability for the Escalante Station will be significantly reduced.  The second proceeding is an application by the City of Gallup for a permit to appropriate ground water within the underground water basin near Gallup.  The City of Gallup seeks to increase pumping of ground water from areas near the Escalante Station.  We are involved in the case to assure that any new pumping does not adversely impact the ground water supplies for the Escalante Station.  Court proceedings are underway to determine the outcome of the application.  These water rights proceedings could have a negative impact on our water supplies for Escalante Station, requiring us to secure alternative water supplies (at a cost which would likely be higher than the cost of the water supplies currently being used).

We are also involved in a water rights proceeding in the State of Colorado that could impact the water rights of Burlington Generating Station.  The Hutton Foundation filed a complaint in the Water Court for Water Division No. 1 seeking relief that would require the state engineer to administer ground water in conjunction with surface water in order to meet Colorado’s obligations under the Republican River Compact.  If successful, such relief could limit the

availability of water to well users, including us, requiring us to secure alternative water supplies (at a cost which would likely be higher than the cost of the water supplies currently being used).

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 substantial costs to obtain licenses, permits and approvals from various federal, state and local agencies.  For example, 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 and updated 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 fifteen 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.

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, established national air quality standards for major pollutants, and required 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 sulfur dioxide (SO₂) and nitrogen oxides (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, 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 will impact coal‑based generating facilities to a greater extent than others.

Our facilities are currently equipped with pollution controls that limit emissions of SO₂, NOx, and particulates below the Clean Air Act and permit requirements.  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 3 has an activated carbon injection system to control mercury emissions.  Escalante Station also has an activated carbon injection systems to control mercury.  Springerville Unit 3 has scrubbers to remove SO₂, baghouses for particulate removal, low NOx burners and selective catalytic reduction equipment for NOx control, and activated carbon injection system for controlling mercury emissions.  Nucla Generating Station includes a Circulating Fluidized Bed with limestone for SO₂ removal and baghouses for particulate removal.

Basin and the Public Service Company of New Mexico, as the respective operators for the Laramie River Generating Station and the San Juan Generating Station, are responsible for environmental compliance and reporting for those facilities.  TEP is the operator of Springerville Unit 3 and is responsible for environmental compliance of the 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, San Juan 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 generation 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 sulfur dioxide 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 sulfur dioxide 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 2044 and we have additional general account allowances that would provide for additional years based on our current usage rate.

Greenhouse Gases and the Clean Power Plan.    In 2014, the EPA proposed emission limits and emission guidelines of carbon dioxide for existing generating facilities in a comprehensive proposed rule referred to as the ‘‘Clean Power Plan.’’  On August 3, 2015, the EPA issued a pre-publication version of a final rule regarding emissions of carbon dioxide from certain fossil fuel-fired electric generating units.  On October 23, 2015, the final rule was published in the Federal Register.  The Clean Power Plan establishes guidelines for states to develop plans to limit emissions of carbon dioxide from existing units.  Emissions of carbon dioxide from our plants totaled approximately 14.1 million short tons in 2014.  The goal of the rule is a reduction in carbon dioxide emissions from 2005 levels of 32 percent nationwide by 2030 and specifies interim emission rates phasing in between 2022 and 2029.  At this time it is not possible to understand how we will be impacted (financially or operationally) in each state, as that information will be developed in state specific plans.  Under the final rule, states are required to submit a final compliance plan, or an initial plan with an extension request, to the EPA, by September 2016, or no later than September 2018 with an approved extension.  However, the Supreme Court issued a stay of the Clean Power Plan on February 9, 2016, as such, the 2016 date is delayed and the other dates are most likely to be delayed.  Once approved, states must implement their plan to ensure power plants achieve the interim carbon dioxide emissions performance goals.

The final state goals for carbon dioxide emissions per MWh in year 2030 and beyond under the Clean Power Plan for the five states where we would be impacted are as follows: Arizona—1,031 lb/MWh; Colorado—1,174 lb/MWh; Nebraska—1,296 lb/MWh; New Mexico—1,146 lb/MWh; and Wyoming—1,299 lb/MWh.  Each of these goals is substantially below the carbon dioxide emission rate of a well-designed coal-fired unit and assumes increased reliance on a combination of natural gas-fired and renewable energy sources, with coal-fired generation being dispatched less often or curtailed entirely.  The EPA also proposed a federal plan that would be implemented should states fail to submit acceptable plans.  We submitted comments on the proposed federal plan, which were due on January 21, 2016.

The Clean Power Plan is the most complex and wide-ranging regulation under the Clean Air Act and litigation challenging the final rule is ongoing.  We, along with 27 states, including Arizona, Colorado, Nebraska and Wyoming, other utilities and national trade organizations, have filed petitions for review of the Clean Power Plan with the D.C. Circuit Court of Appeals.  We, along with 24 states, other utilities and national trade organizations, also filed motions to stay the Clean Power Plan with the D.C. Circuit Court of Appeals.  On January 21, 2016, the D.C. Circuit Court of Appeals denied the motions to stay the Clean Power Plan, but ordered an expedited briefing schedule and scheduled oral arguments for June 2, 2016.  We, along with 27 states, including Arizona, Colorado, Nebraska and Wyoming, other utilities and national trade organizations, filed applications for immediate stay of the Clean Power Plan with the United States Supreme Court.  On February 9, 2016, the Supreme Court stayed the Clean Power Plan pending judicial review.  The impacts of the final rule and any challenges cannot be determined at this time; however, it could have a material impact on our operations, including increased operating costs, additional investment in new generation (natural gas and renewables) and transmission, investment in energy efficiency programs and decreased operation, or closure of coal-fired plants.

EPA also issued a final NSPS for new and modified units which establishes carbon dioxide emission standards for plants built in the future.  This NSPS does not create emission standards for Holcomb, but states that if the plant moves forward, EPA will create a separate rule for Holcomb due to the fact that it is so far along in the process.  We, along with 25 states, other utilities and national trade organizations, have filed petitions for review of the NSPS with the D.C. Circuit Court of Appeals.

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, with a compliance deadline in April 2015.  We were among the parties that legally challenged the MACT rule, but the rule was upheld by the D.C. Circuit Court of Appeals in April 2014.  The Supreme Court agreed to review a narrow provision that focuses on whether the EPA reasonably considered costs in developing the MATS, and oral arguments in the case were heard on March 25, 2015.  On

June 29, 2015, the Supreme Court ruled that the EPA acted improperly when it did not consider the cost of regulation in determining that it was “appropriate and necessary” to issue the MATS rule.  The Supreme Court instructed the D.C. Circuit Court of Appeals to determine whether the rule should remain in place while the EPA reconsiders its “appropriate and necessary” determination.  On December 15, 2015, the D.C. Circuit Court of Appeals remanded the proceeding to EPA without vacatur of the MATS rule.  The EPA is on track to issue a final supplemental finding by April 15, 2016.  We are in full compliance with the rule’s emission limits, which required new emission controls on Craig Station Unit 3, Springerville Unit 3, Escalante Station and Laramie River Generating Station.  The Colorado Department of Public Health and Environment approved our request to extend the MATS hydrochloric acid mist compliance date to April 16, 2016 for the Nucla Generating Station.  Nucla Generating Station currently meets all other compliance aspects of the Mercury and Air Toxics Standards rule.  The Arizona Department of Environmental Quality approved TEP’s request to extend the MATS mercury compliance date to April 16, 2016 for Springville Unit 3 and TEP subsequently installed an activated carbon injection system for controlling mercury emissions at Springerville Unit 3.

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 decade, 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 NSR 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 ambient air quality standard for ozone from 75 parts per billion (ppb) to 70 ppb.  Currently, J.M. Shafer Generating Station and Knutson Generating Station are our only generation facilities that are located in an ozone nonattainment area.  It is not known whether the more stringent ozone standard may designate new areas as nonattainment and create more difficult permitting and operation conditions for additional generation facilities.  Implementation of an ozone standard at 70 ppb will prove challenging because of the significance of “background” concentrations of ozone, which can be increased by several factors that yield particularly great influence in the western United States.  Such factors include interstate and international transport, biogenic and wildfire emissions, and greater solar radiation at higher elevations.

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 developed SIPs.  Each state was challenged by the EPA and legal processes are ongoing.

Craig Station Units 1 and 2 are subject to BART.  In 2007, the State of Colorado determined that the upgraded pollution controls completed in 2004, which include replacement of electrostatic precipitator units with baghouses to increase particulate removal, upgraded scrubbers to increase SO₂ removal and the installation of low NOx burners, met the BART rule; therefore, no additional controls were necessary.  The original BART determinations were part of Colorado’s SIP, which was not approved by the EPA.  The EPA told Colorado that the EPA would not approve the SIP;

therefore the state launched a new SIP rulemaking effort.  Colorado created a new SIP with more stringent SO₂ and NOx emission limits for Craig Station Units 1, 2 and 3.  Under the existing, approved SIP, we committed to NOx emissions rates that will result in the installation of selective catalytic reduction on Craig Station Unit 2 no later than December 31, 2017.  We estimate our cost of such project is approximately $42 million.  The existing, approved SIP allowed for less stringent emissions limit on Craig Station Units 1 and 3, therefore significantly limiting the amount of additional controls required on those units.  The Wild Earth Guardians and National Parks Conservation Association filed a lawsuit against EPA for approving the plan and we entered a court‑ordered mediation process.  The result of mediation is a settlement agreement that commits us to a NOx emission rate limit for Craig Station Unit 1 that will require installation of selective catalytic reduction by August 31, 2021, at an estimated cost to us of approximately $42 million.  The legislature of Colorado approved the new rule and delivered it to the EPA for review.  In the case of each Craig Station unit, compliance involves capital and operational expenditures for NOx controls.

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 sulfur dioxide 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 other assets.  Wyoming developed a SIP that required low NOx burners and overfire air at Laramie River Generating Station, however the EPA instead proposed a Federal Implementation Plan that also requires selective catalytic reduction.  The Federal Implementation Plan is under administrative and legal challenges.

The Regional Haze Rule requires that states assess progress under their state plans every five years, and periodically 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 used by utilities in the event they have excess emissions during a startup, shutdown or malfunction events.  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 make SIP submissions to rectify the specifically identified deficiencies in their respective SIPs.  Colorado recently 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.  We are working with state environmental agencies to address changes to SIPs in each of the other noted states.  We cannot predict the outcome of these proceedings at this time.

Water Quality

The Clean Water Act.  The Clean Water Act regulates the discharge of process wastewater and certain storm water under the National Pollutant Discharge Elimination System permit program.  At the present time, we have the required permits under the program for all of our electric 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), Nucla Generating Station and Rifle Generating Station each discharge process wastewater to nearby water bodies.  Nucla Generating Station discharges to the San Miguel River through a pond system that was upgraded in 1997 and 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.  The EPA’s final effluent limitation guidelines rule for steam electric power generation was published on November 3, 2015, with an effective date of January 4, 2016.  It appears that the rule will have minimal impact on operations at Nucla Generating Station, Rifle Generating Station, and J.M. Shafer Generating Station.  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, Nucla Generating Station and Nucla Ash Site, 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.  In August 2014, the EPA issued final regulations that provided several compliance alternatives for existing plants such as using existing technologies, or adding fish protection systems.  Section 316(b) is applicable to Craig Station and Nucla Generating Station; however, impacts are anticipated to be minor as the facilities operate closed cycle cooling systems minimizing impingement and entrainment.

In April 2014, the EPA and the U.S. Army Corps of Engineers proposed an expansion of regulatory authority under the Clean Water Act through broadening the definition of a “Water of the United States.”  We submitted comments on the proposed rule in November 2014, identifying clarifications needed on the applicability of the ditch and waste treatment system exclusions.  A final redefinition of “Waters of the United States” was announced in late May 2015 and published in the Federal Register on June 29, 2015.  However, there is currently a nationwide stay issued by the United States Court of Appeals for the Sixth Circuit that is in effect as of October 9, 2015.  Currently, we are continuing to review the rule to assess impacts and determine appropriate next steps.

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 have been updated to meet the new 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 waste 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 Nucla Generating Station and Escalante Station the combustion by‑products are placed in a designated landfill.  The mine‑fill and landfills are regulated by state environmental agencies and all required permits are in place.  The EPA in 2010 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. Pursuant to litigation, 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 costs relating to the management of such by‑products to be approximately $10 million.  We are meeting all initial compliance obligations that became effective on October 19, 2015.

Renewable Portfolio Standards.  Colorado law requires each electric cooperative to obtain at least 6 percent and 10 percent of its energy requirements from renewable sources by year end 2015 and 2020, respectively.  In 2013, Colorado law was amended to add a separate RPS requirement requiring that at least 20 percent of the energy we provide to our Colorado Members at wholesale come from renewable sources by 2020 and each year thereafter.  Colorado law permits us to count renewable sources utilized by our Colorado Members for their RPS requirement towards compliance with our separate RPS requirement.  New Mexico law requires our New Mexico Members to obtain 5 percent of their energy requirements from renewable sources by January 1, 2015, and increase that amount by 1 percent annually until 10 percent is achieved in 2020.  Under the wholesale electric service contracts with our Members, our Members may elect to provide up to 5 percent of their requirements from distributed or renewable generation owned or controlled by them.  We currently provide sufficient energy from renewable sources to meet our

Members’ current obligations under the RPS requirements and expect to be able to continue meeting our Members’ RPS obligations through 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.

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; 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.  The centerpiece of the United States’ commitment is the Clean Power Plan, which in February 2016 was stayed by the Supreme Court.

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.

Mine Reclamation.  The EPA is working with the Office of Surface Mining and state mine reclamation regulators to develop a better understanding of mine placement practices for coal ash.  The Office of Surface Mining may in 2016 issue a proposed rulemaking establishing requirements and standards that apply when coal ash is used during reclamation at surface coal mining operations.  Until these rules are promulgated, we cannot determine what, if any, controls we may be required to implement to comply with the regulation.

Mine Plan Approval.  Colowyo Coal is expected to modify and expand operations to access coal reserves for future production as current mining plans are completed and land is reclaimed.  Colowyo Coal received approval from Colorado state authorities with primacy to implement the federal mining permit program.  Before the permitted operations may proceed, OSMRE must complete a mine plan review of the proposed modification and ensure compliance with applicable federal laws, including the National Environmental Policy Act.  Then OSMRE must obtain approval of the modification from the Department of Interior, Assistant Secretary for Land and Minerals Management.  The Department of Interior’s January 15, 2016 pause on new federal coal leasing expressly excludes mine plan reviews by OSMRE and lease modifications under certain acre thresholds.  The leases Colowyo Coal holds for continued development are not subject to the pause.

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.  The EPA is expected to release a proposed rulemaking for more strict controls of PCBs in June of 2016.  Until that rule is proposed it is not possible to estimate impacts to our operations.

Endangered Species Act.  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 add costs to electric transmission project.  Of the several hundred species involved in the litigation settlement, we estimate that approximately 30 have the potential to affect our assets.  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 Endanger Species Act, in large part on the basis of federal land management agency-based conservation plans.  In 2016, the U.S. Fish and Wildlife Service may issue a 4(d) rule for the gunnison sage-grouse.  The listing of the lesser prairie-chicken as a threatened species was

vacated in 2015 by a court for the western district of Texas.  We are monitoring each of these issues as they develop over time.

TRANSMISSION

We have ownership or capacity interests in approximately 5,560 miles of high‑voltage transmission lines and own or have major equipment ownership in approximately 357 substations and switchyards.  See “PROPERTIES” for a description of our transmission facilities.

Our system is interconnected with those of other utilities, including WAPA, Nebraska Public Power District, Black Hills Power, Inc., PacifiCorp, PSCO, Platte River Power Authority, Colorado Springs Utilities, Basin, TEP, Public Service Company of New Mexico and Deseret Generation & Transmission Cooperative.  The majority of our transmission facilities operate as part of the Western Interconnection, an interconnected transmission grid which serves the western portion of the United States and Canada.  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 the transmission infrastructure in our service area and participate in many joint projects with other transmission owners within the interconnected grid.  We believe these additions insure we can access and deliver into the Eastern and Western Interconnection marketplaces.

On June 3, 2015, our Board approved us becoming 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 4.5 percent of our total loads and facilities.  On October 30, 2015, SPP filed revisions to its Open Access Transmission Tariff 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.  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 processes are expected to begin during the first quarter of 2016.  We are now subject to greater oversight by FERC, including review of our costs of providing transmission service in the Eastern Interconnection, and must comply with the requirements of SPP, which is also subject to FERC jurisdiction.

FERC

The FPA authorizes FERC to oversee the wholesale sale and transmission of electricity in interstate commerce by public utilities, as that term is defined in the FPA.  We are not subject to the general “public utility” regulation of FERC under the FPA because of the exempt status of our Members.  See “— RATE REGULATION.”  FERC requires non‑public utilities such as us to comply with several requirements that are applicable to public utilities, including the requirements to provide open access transmission service and engage in regional planning of transmission facilities, as a condition of obtaining transmission service from public utilities.  We are also subject to certain reporting obligations applicable to all electric utilities, other FERC orders to the extent that they apply generally to non‑public utilities, and FERC’s oversight with respect to transmission planning, investment and siting, reliability standards, price transparency, and market manipulation.

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 proposed revised Board policy is consistent with the provisions of PURPA and the implementing regulations of FERC.  The proposed 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.  FERC has approved similar mechanisms in the past.  In March 2016, our Board

adopted the revised Board policy.  We are also subject to certain 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.

Open Access Transmission Service

Use of our transmission facilities is governed by an open access transmission tariff.  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.  FERC also extended the open access requirement to non‑public utilities (such as us) through a reciprocity requirement whereby a non‑public utility receiving transmission service under a public utility’s open access tariff must provide to the transmission service provider comparable open access to the non‑public utility’s own transmission facilities.  Thus, we are obligated to offer reciprocal service over our transmission facilities to those public utilities from which we receive open access transmission service, on a basis comparable to our use of their transmission facilities.  Since 2001, we have offered transmission service under an open access tariff for service across our system on a non‑discriminatory basis.  Because we are not a public utility, we are not required to formally file this tariff with FERC, and our tariff rates for transmission service provided in the Western Interconnection are not subject to FERC’s public utility rate review.

As a non‑public utility, we are 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 have implemented FERC’s Standards of Conduct procedures, 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.

FERC has express, statutory authority under Section 211A of the FPA to require “unregulated transmitting utilities” (such as us) to provide transmission service to all qualified customers on an open access basis at rates and terms that are comparable to those that the utility employs in using its own system.  In Order No. 890, FERC stated that it may take action under Section 211A with respect to non‑public utilities that do not adopt the open access tariff modifications that FERC required public utilities to adopt.  We have not been the subject of an order under Section 211A.

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, 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 comply with Order No. 1000 by participating in

regional and interregional transmission planning and cost allocation processes in WestConnect.  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 parts of the states of Arizona, New Mexico, Colorado, Wyoming, Nevada, and California.  In December 2014, we signed the WestConnect Planning Participation Agreement, which governs the WestConnect Order 1000 planning process.

FERC has also provided for rate incentives for public utilities as a means of encouraging investment in new transmission facilities.  Although FERC’s incentive program is focused on public utilities, FERC has encouraged non‑public utilities to participate in new transmission projects and has suggested that non‑public utilities may propose incentives.  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 generation 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 also has 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.

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 generation facilities are included in two regional reserve sharing pools, the Rocky Mountain Reserve Group 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 our Lead Regional Entity.  The intent of the MREE program is to streamline compliance and enforcement efforts for entities registered in multiple regions.

In 2015, we were audited by WECC and are scheduled for a future compliance audit in 2018 as part of a three-year audit cycle.  While some violations were cited from the 2015 audit, and in each of the previous audits conducted in 2009, 2011 and 2012, only minimal penalties were assessed.  The minimal penalties that were assessed took into account our efforts to fully cooperate with the investigation, our commitment to take action beyond that minimally required for baseline compliance, and the fact that none of the issues individually posed a serious or substantial risk to the reliability of the bulk power system.  We have continued to develop and improve our reliability compliance program.

ITEM 1A.RISK FACTORS

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

Our costs of compliance with environmental laws and regulations are significant and have increased in recent years.  Future environmental laws and regulations, including laws and regulations designed to address climate change, air and water quality, coal combustion byproducts and other matters may increase our compliance costs or liabilities in the future.

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.

Generally, existing environmental regulations are becoming increasingly stringent, and we may also be subject to new legislation or regulation, including legislation or regulation relating to greenhouse gas emissions or renewable or clean energy standards.  We have spent substantial amounts on capital expenditures for air pollution control and related emissions projects to achieve and maintain compliance with applicable EPA rules and regulations at our facilities.  Without taking into account the Clean Power Plan, we expect that we will spend an additional $300 million through 2020 in efforts to maintain compliance.  Currently, our existing generating facilities generate approximately 63 percent of our energy resources.  More stringent standards may require us to modify the design or operation of existing facilities or purchase emission allowances.  These actions may result in substantial increases in the cost of electricity to our Members.

In 2015, the EPA finalized emission limits and emission guidelines of carbon dioxide for existing generating facilities in a comprehensive rule referred to as the ‘‘Clean Power Plan.’’  The EPA’s Clean Power Plan for existing generating facilities creates state goals, which are to be reached through measures inside and outside of the electric power generation and transmission industry.  We are analyzing the potential impact of this final rule.  The magnitude of the impact on our existing generating facilities is yet to be determined and will depend on the implementation of state specific plans by each of the states in which we have affected assets.  States are to have plans, including regulations, in place in 2017 or 2018.  However, with the United States Supreme Court’s stay of the Clean Power Plan these dates are most likely to be delayed.  EPA’s final rule establishes an implementation date of 2022 and a compliance date of 2030.  The impacts of the final rule and any challenges cannot be determined at this time; however, it could have a material impact on our operations, including increased operating costs, additional investment in new generation (natural gas and renewables) and transmission, investment in energy efficiency programs and decreased operation, or closure of coal-fired plants.

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.  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.  Any additional federal or state environmental restrictions imposed on our operations could result in significant additional compliance costs, including capital expenditures.  Such costs could affect future unit retirement and replacement decisions and may result in significant increases in the cost of electric service.  The cost impact of future legislation or regulation will depend upon the specific requirements thereof and cannot be determined at this time, but could be significant.

Our ability to raise our Members’ wholesale rates may be limited and we may be 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 44 Members.  In March 2013, three of our Colorado Members and several of their large industrial customers filed a complaint at the COPUC alleging that our A-37 rate design was unjust and unreasonable.  In December 2015, we and three Colorado Members filed a joint motion to withdraw the complaint and dismiss the proceeding.  The joint motion was approved by the administrative law judge in January 2016.

According to New Mexico law, we are required to file our Member rates with the NMPRC and the NMPRC only has regulatory authority over our rates in the event three or more of our New Mexico Members file a request to review our rates and the NMPRC finds such request to be qualified.  Some of our New Mexico Members filed for such review in 2012 and 2013.  The procedural schedule related to such rate reviews by the NMPRC are currently suspended to allow the parties time for further negotiations towards a global settlement.  See ‘‘LEGAL PROCEEDINGS.’’

Member challenges to the rates approved by our Board 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 may have an adverse effect on our results of operations and financial condition.  The outcome of the rate proceeding in New Mexico, or whether a global settlement will be reached, is difficult to predict at this time.  See ‘‘MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Factors Affecting Results—Rates and Regulation.’’

We have a substantial amount of indebtedness and we expect this amount to increase.

As of December 31, 2015, we had total debt 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.  Additionally, we expect to incur substantial indebtedness in the future and we forecast that we will have approximately $3.8 billion of total debt outstanding in 2020.  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 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.  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 and transmission facilities to meet our Members’ demands, which may require substantial additional capital expenditures which will significantly 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.

In order to meet expected Member-system demand growth, we regularly evaluate options, including the potential development of new generation and transmission facilities to serve our Members and long-term purchases of power from generation facilities owned by others or new generation facilities that may be developed by others.  Without taking into account the Clean Power Plan, in the years 2016 through 2020, we estimate that we may invest approximately $1.4 billion in new facilities and upgrades to our existing facilities, including, but not limited to, investment in new generating facilities and transmission improvements, upgrades to our existing generating facilities and transmission facilities and investments in our coal mining facilities.  We expect to incur significant indebtedness in connection with this capital expenditure program.  Without taking into account the Clean Power Plan, beginning in year 2020, we estimate that we may need to invest substantial amounts to develop or lease additional generating capacity, and we may also need to invest substantial amounts for new transmission facilities and improvements to our existing transmission facilities.  The specific projects we undertake and the amount of such investments are subject to

uncertainties and may be influenced by many factors, including:

Any construction program would require substantial additional capital, requiring us to obtain financing resulting in a significant increase in the amount of our long-term debt.  A significant increase in long-term debt would likely increase the cost of the electric service we provide to our Members.  Failure to obtain financing may adversely affect our results of operations, liquidity and financial condition.

Our ability to access 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 could adversely affect our financial condition and future results of operations.

We rely on access to capital for construction of new generation and transmission facilities and as a significant source of liquidity for capital expenditures not satisfied by cash flow generated from operations.  Without taking into account the Clean Power Plan, in the years 2016 through 2020, we estimate that we may invest approximately $1.4 billion in new facilities and upgrades to our existing facilities which will require us to take on significant 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 disruptions include:

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 generation and transmission facilities and to construct future generation and transmission 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, 2015, we had $523 million in variable rate debt.  The interest rates on this debt could increase.  The interest rates could also increase if an unrelated third-party associated with the debt, such as a remarketing agent or liquidity provider, displayed financial problems.

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 2014 data, industrial and large commercial customers account for approximately 38 percent of our Members’ energy sales.  A large percentage of these sales are in energy production, extraction and transportation, particularly in our forecasted load growth.  The 15 largest customers of our Members, a substantial percentage of which are in energy production, extraction and transportation, total approximately 18.8 percent of the aggregate retail electric energy sales of our Members, based on the same 2014 data.  A significant downturn in the economy or sustained low natural gas prices 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.

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 contract with us.  In 2015, approximately 90 percent of our revenues from electric sales was 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 the wholesale electric service contracts.  These defaults could result from financial difficulties of one or more Members or because of intentional actions by our Members.  We are also exposed to the risk that one or more of our Members may withdraw from membership in us.  Pursuant to our Bylaws, a Member may withdraw from membership in us upon compliance with such equitable terms and conditions as the 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.  If we underestimate the monetary value of a Member’s obligation or a significant number of our Members withdraw, our ability to satisfy our financial obligations could be adversely affected.  Furthermore, if a significant portion of our Members withdraw, we may be required to prepay certain of our long-term debt.  Our results of operations and financial condition could be adversely affected if a significant portion of our Members default on their obligations to us or withdraw from membership in us.

Changes in fuel prices could have an adverse effect on our cost of electric service.

We are exposed to the risk of changing prices for fuels, including coal, natural gas and oil.  We have made certain arrangements to mitigate our expenses to fuel prices; however, these arrangements do not cover all of our risk exposure to increases in the prices of fuels.  Therefore, increases in fuel prices could significantly increase the cost of electric service we provide to our Members and affect their ability to perform their contractual obligations to us.

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.  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.

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 reputation may be damaged.

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.  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.

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 and expense to repair security breaches or system damage and could lead to litigation, regulatory action, including penalties or fines, and an adverse effect on our reputation.  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.

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

Our business model is to provide our Members with a reliable, cost‑based supply of electricity.  Significant technological advancements are taking place in the electric industry, including advancements related to self‑generation and distributed energy technologies such as fuel cells, batteries, micro turbines, wind turbines and solar cells.  Adoption of these technologies may continue to increase because of advancements or government subsidies reducing the cost of generating electricity through these technologies to a level that is comparable with, or lower than, our cost of generating power.  There is also a perception that generating electricity through these technologies is more environmentally friendly than generating electricity with fossil fuels.  Increased adoption of these technologies could reduce electricity demand and the pool of customers from whom fixed costs are recovered, resulting in under recovery of our fixed costs.  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 value of our facilities, our financial condition and results of operations could be adversely affected.

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, 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.  On the retail side, states in which our Members’ service territories are located do not have retail competition legislation.  Federal legislation could mandate retail choice in every state, but the prospect of such legislation has diminished due to a variety of factors, including the risks associated with retail competition, the state of the economy, and commodity prices.

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 other utilities, 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 may consist of competition from other electric companies or annexations by municipalities.  Generally, we serve our Members in rural territories that are less attractive to competitors.

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 and transmission facilities, by entering into long‑term power purchase agreements, 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 generation and transmission 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 generation 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 are exposed to cost uncertainty in connection with our construction projects at existing generation and new and existing transmission facilities.

Our existing facilities require ongoing capital expenditures in order to maintain efficient and reliable operations.  Many of our 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.  While we do not currently have a generation plant under construction, we continually employ best operational and maintenance practices at our existing facilities.

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

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.

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.

The demand for access to existing transmission lines may make it increasingly difficult in the future for us to acquire transmission capacity rights without constructing new transmission facilities.  In most cases, construction of transmission lines presents numerous challenges.  Environmental and state and local permitting processes 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 must rely on purchases of market priced electric power, which could put increased pressure on electric rates.

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

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

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

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

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.  See ‘‘LEGAL PROCEEDINGS.’’  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.  In response to the increase in litigation on these types of claims, we have increased our liability insurance coverage.  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.

Renewable Portfolio Standards may increase our costs of operation and affect the utilization of current generation facilities.

Colorado and New Mexico have each enacted a RPS that establishes minimum amounts of electric energy (or an equivalent amount of renewable energy credits) that our Members are required to obtain from renewable sources or that we are required to provide to our Colorado Members from renewable sources.  Colorado law requires each electric cooperative to obtain at least 6 percent and 10 percent of its energy requirements from renewable sources by year end 2015 and 2020, respectively.  Colorado law was amended in 2013 to add a separate RPS requirement requiring that at least 20 percent of the energy we provide to our Colorado Members at wholesale come from renewable sources by 2020 and each year thereafter.  Colorado law permits us to count renewable sources utilized by our Colorado Members for their RPS requirement towards compliance with our separate RPS requirement.  New Mexico law requires our New Mexico Members to obtain 5 percent of their energy requirements from renewable sources by January 1, 2015, and increases that amount by 1 percent annually until 10 percent is achieved in 2020.  Under the wholesale electric service contracts with our Members, our Members may elect to provide up to 5 percent of their requirements from distributed or renewable generation owned or controlled by them.  We currently provide sufficient energy from renewable sources to meet our Members’ current obligations under the RPS requirements and expect to be able to continue meeting our Members’ RPS obligations through 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.  Neither we nor our Members are subject to an RPS in any other state.

We have executed approximately 368 MW of wind‑based power purchase agreements and 85 MW of solar‑based power purchases as a part of our plan to meet these RPS requirements.  Our access to these new renewable resources has been secured at what we believe are reasonable prices due to the federal Production Tax Credit and Investment Tax Credit and advances in wind technology that have led to improvements in capacity factors.  Integration of these intermittent power sources into our overall generation portfolio remains a concern, but we believe solutions will be developed that are reasonably cost effective.

If we cannot obtain the required percentages of energy from renewable resources to satisfy the RPS requirements, we will need to purchase an equivalent amount of renewable energy credits to meet the energy shortfall at market price from the secondary market, the prices of which may be higher than our own generation costs.

An additional consequence of the Colorado and New Mexico RPS is the strain imposed on the regional transmission system by the increasing capacity of intermittent generation facilities integrated, interconnected and

planned to be interconnected with the transmission grid.  The addition of major new wind projects will likely require accompanying transmission projects as much of the latent capacity in the system has been exhausted.

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 2015, purchased power provided approximately 37 percent of our energy requirements.  These purchases consist of a combination of purchases under long‑term contracts and market purchases of electric power in the spot markets.  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.  If this occurs, we may be forced to enter into alternative contractual arrangements or enter into spot 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 spot market purchases exposes us to increases in electric power prices.

Our long‑term power purchase contracts include contracts with WAPA and Basin, consisting of approximately 15.2 percent and 12.9 percent, respectively, of our Member sales in 2015.  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 would have an adverse effect on our results of operations.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None

ITEM 2PROPERTIES

Generating Facilities

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

*The Unit Rating for each generating facility is subject to seasonal fluctuations to account for various operating conditions.

Craig Generating Station.  Craig Station is a three‑unit, 1,303 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 have capacities of 427 MWs and 428 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 653 MWs.

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.

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 Missouri Basin Power Project, and jointly owned as tenants in common by us and five other regional utilities pursuant to a participation agreement.  We own a 24.1 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 412 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 416 MW unit that is part of a four unit coal‑fired, 1,578 MW electric generating facility operated by TEP.  Under contractual agreements, we, as the lessee of Springerville Unit 3, are taking 416 MWs of capacity from the unit and selling 100 MWs of such capacity to Salt River Project.  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.

Nucla Generating Station.  Nucla Generating Station is a 100 MW coal‑fired electric generating facility located near Nucla, Colorado.  Nucla Generating Station is wholly owned and operated by us.

San Juan Generating Station Unit 3.  San Juan Generating Station is a four unit, 1,600 MW, coal‑fired electric generating facility located in the Four Corners area of New Mexico.  We own an 8.2 percent interest in San Juan Unit 3, which has a capacity of 488 MWs.  Our total share of San Juan Unit 3’s capacity is approximately 40 MWs.  Public Service Company of New Mexico, the New Mexico Environment Department and the EPA have agreed to pursue a plan to comply with federal visibility rules for the San Juan Generating Station.  The plan would include the retirement of two units by the end of 2017.  We expect that San Juan Generating Station Units 2 and 3 will be retired by December 31, 2017.  We have executed a suite of agreements with the other eight owners of the San Juan Generating Station and PNMR Development and Management Corporation, which upon satisfaction of certain conditions will become effective and under which, among other things, we will exit active participation in station operations upon retirement of San Juan Unit 3 at the end of 2017.  On January 31, 2016, some of these agreements became effective including the San Juan Project Restructuring Agreement.

Burlington Generating Station.  Burlington Generating Station consists of two 50 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.

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.  Knutson Generating Station is wholly owned and operated by us.  This facility is under contract to PSCO under a tolling arrangement through April 2016, which is an arrangement whereby the purchaser provides its own natural gas for generation of electricity.

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.  Limon Generating Station is wholly owned and operated by us.  One of the two units is under contract to PSCO under a tolling arrangement through April 2016.

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 85 MW, natural gas fired combined 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.

J.M. Shafer Generating Station.  J.M. Shafer Generating Station is a combined cycle, 272 MW, natural gas‑fired 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 Thermo Cogeneration Partnership, L.P. 122 MWs are sold to PSCO under a tolling agreement through June 2019 and the balance of the output is sold to us under a separate tolling agreement through June 2019.  Our interest in the tolling agreement, as

purchaser, is subject to the lien of our Master Indenture, but J.M. Shafer Generating Station is not subject to the lien of our Master Indenture.

AltaGas Brush Energy.  We have a gas tolling arrangement through December 31, 2019 with AltaGas Brush Energy Inc. to provide intermediate load generating capacity of 70 MWs.  Under this tolling arrangement, we are entitled to receive the energy output of the source facility at our call, and we supply the natural gas to operate the source facility.  The source facility is a combined cycle facility located near Brush, Colorado and was installed in 1994.

Transmission

As of December 31, 2015, we own, lease, or have undivided percentage interest in transmission lines as described in the following table:

We are an ownership participant in the Missouri Basin Power Project (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 357 substations and switchyards.  All of our interest 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 3LEGAL PROCEEDINGS

NMPRC Proceeding.  On October 19, 2012, we gave notice, as required by New Mexico law, to the NMPRC of our new A‑37 wholesale rate which was scheduled to become effective on January 1, 2013.  The rate would have increased revenue collected from all 44 of our Members by approximately 4.9 percent, with revenues from our 12 New Mexico Members increasing by approximately 6.7 percent.  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 and appointed a hearing examiner to conduct a hearing and establish reasonable rate schedules pursuant to

New Mexico law.  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.  We intend to pursue our federal challenge to the actions of the NMPRC.  Also, on January 25, 2013, we made an additional filing at the NMPRC seeking interim rate recovery from our New Mexico Members during the pendency of the NMPRC proceedings on the original rate filing.  The NMPRC denied the filing on March 13, 2013.  We appealed that denial to the New Mexico Supreme Court.  On April 6, 2015, the Court vacated the NMPRC denial of our interim rate recovery filing and remanded the case to the NMPRC for any proceedings that may be necessary to comply with the Court’s order.  On June 25, 2013, we filed to withdraw the A‑37 rate.  On July 3, 2013, the NMPRC denied the filing to withdraw and ordered the A‑37 rate filing to be consolidated with the A‑38 rate filing described below.  On September 10, 2013, we gave notice, as required by New Mexico law, to the NMPRC of our new A‑38 wholesale rate which was scheduled to become effective on January 1, 2014.  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 and assigned the consolidated A‑37 and A‑38 rate filings to a hearing examiner.  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 (unless terminated earlier as provided in the preliminary mediation agreement) 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.  We filed notice of the temporary rate rider with the NMPRC and it became effective on October 2, 2014.  The temporary rate rider was applied in conjunction with the 2012 wholesale rate to recover additional revenue from the New Mexico Members in an annualized amount of $7 million per year, which was prorated beginning October 2 for 2014.  In 2015 and 2014, the overall revenue impact of the New Mexico Members paying a lower rate was approximately $10.7 million and $16.4 million, respectively.  On October 9, 2015, we gave notice, as required by New Mexico law, to the NMPRC of our 2016 wholesale rate, or the A‑39 rate.  No New Mexico Member filed a protest with the NMPRC of the A‑39 rate and thus the A‑39 rate became effective on January 1, 2016 without NMPRC review or approval. 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 7, 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.

COPUC Proceeding.  On March 4, 2013, three of our Colorado Members and several of their large industrial customers filed a complaint at the COPUC alleging that our A‑37 rate design was unjust and unreasonable.  On April 4, 2013, we filed a motion to dismiss the complaint arguing lack of jurisdiction by the COPUC over our wholesale rates.  The COPUC assigned the matter to an administrative law judge.  The judge bifurcated the case into deciding first, whether the COPUC had the jurisdiction to hear such a case against us, who has been historically regulated by its membership through its Board, and secondly to hear the facts in the case depending on jurisdiction.  The administrative law judge conducted a hearing in July 2013 and ruled on September 11, 2013 denying our motion to dismiss.  In October 2013, we appealed the administrative law judge’s decision to the full commission and on December 18, 2013, the commission granted in part and denied in part our motion contesting the administrative law judge’s decision and remanded the case to the administrative law judge to hold a hearing on limited issues.  In November 2014, we and the three Colorado Members executed a preliminary agreement providing for a temporary optional rate effective December 1, 2014 and to continue through no later than December 31, 2015, available to all non‑New Mexico Members and a suspension of the procedural schedule related to the complaint.  The administrative law judge entered a decision on November 28, 2014 holding this matter in abeyance until December 31, 2015 to give the parties time to work toward a global settlement and permanent rate.  On December 28, 2015, we and the three Colorado Members filed a joint motion with the COPUC to withdraw the complaint and dismiss the proceeding.  On January 19, 2016, the administrative law judge granted our joint motion to withdraw the complaint, dismiss the proceeding with prejudice and close the proceeding.  The administrative law judge’s order has become effective by operation of law.

Las Conchas Fire.  In June 2011, a wildfire in New Mexico, known as the Las Conchas Fire, burned for five days in northern New Mexico, primarily on national forest service land in the Santa Fe National Forest.  Six plaintiff

groups, comprised of property owners in the area of the Las Conchas Fire, filed separate lawsuits against our Member, JMEC, in the Thirteenth District Court, Sandoval County in the State of New Mexico.  Plaintiffs alleged that the fire ignited when a tree growing outside the right of way fell onto a distribution line owned by JMEC as a result of high winds.  On January 7, 2014, the district court allowed all parties and related parties to amend their complaints to include the addition of us as a party defendant.  These cases are State Farm Fire and Casualty Company, et.  al. v. Jemez Mountains Electric Cooperative, Inc., et. al. (amended complaint filed March 6, 2014); Elizabeth Ora Cox, et. al., v. Jemez Mountains Electric Cooperative, Inc., et. al. (second amended complaint filed January 31, 2014); Norman Armijo, et. al., v. Jemez Mountains Electric Cooperative, Inc., et al. (amended complaint filed January 16, 2014); United Services Automobile Association, et. al. v. Jemez Mountains Electric Cooperative, Inc. (amended complaint filed March 6, 2014); Jemez Pueblo v. Jemez Mountains Electric Cooperative, Inc., et. al. (filed June 10, 2013); and Pueblo De Cochiti., et. al. v. Jemez Mountains Electric Cooperative, Inc., et. al. (filed June 10, 2013).  The allegations in each case were similar.  Plaintiffs alleged that we owed them independent duties to inspect and maintain the right‑of‑way for JMEC’s distribution line and that we are also jointly liable for any negligence by JMEC under joint venture and alter ego theories.  On June 16, 2014, we filed multiple motions for summary judgment including for plaintiffs’ claims related to nuisance, trespass, negligence per se, independent duty, joint venture and alter ego.  On December 29, 2014, we received a demand letter from the U.S. Department of Justice for costs incurred as a result of the fire, also alleging the joint venture theory.  JMEC has settled with the subrogated insurers, executing and funding the deal on December 30, 2014 and on February 7, 2015, the district court dismissed the subrogated insurers’ claims against us with prejudice.  Settlement demands were received from plaintiffs Jemez Pueblo and Pueblo de Cochiti claiming damages in the amount of approximately $34.4 million and $23.9 million, respectively, focusing mainly on damages arising from flooding subsequent to the fire.  On March 9, 2015, the district court granted our motions for summary judgment related to nuisance, trespass, negligence per se, and alter ego, but denied our motions related to independent duty and joint venture.  On March 17, 2015, we filed an application for interlocutory appeal with the New Mexico Court of Appeals related to the district court’s denial of our motions for summary judgment for plaintiffs’ claims related to independent duty and joint venture.  The New Mexico Court of Appeals denied our application for interlocutory appeal on May 27, 2015.  A jury trial commenced on September 28, 2015.  On October 28, 2015, the jury affirmed our position that we and JMEC did not operate as a joint venture or joint enterprise.  The jury did find we owed the plaintiffs an independent duty and allocated comparative negligence with JMEC 75 percent negligent, us 20 percent negligent, and the United States Forest Service 5 percent negligent.  On November 11, 2015, we filed a request with the district court to certify for interlocutory appeal certain issues regarding our duty under a negligence claim, which was denied by the district court in January 2016.  Three or four separate trials will occur in the second half of 2016 and first quarter of 2017 to determine the amount of damages.  We maintain $100 million in liability insurance coverage for this matter.  Although we cannot predict the outcome of these matters at this point in time, we do not expect them to have a material adverse effect on our financial condition or our future results of operations or cash flows.

Tres Lagunas Fire.  In May 2013, near the Village of Pecos, New Mexico, a wildfire known as the Tres Lagunas Fire was ignited and subsequently destroyed timber on thousands of acres and burned for approximately three weeks.  On March 25, 2014, a lawsuit was filed by David Old d/b/a Old Wood, The Viveash Ranch, and River Bend Ranch, LLC, against our Member, MSMEC, in the First Judicial District Court for the County of Santa Fe, New Mexico.  In the complaint, plaintiffs allege that the Tres Lagunas Fire resulted from wind blowing a portion of a dead standing tree into an electric distribution power line owned and operated by MSMEC.  On November 6, 2015, plaintiffs filed a motion to amend their complaint and include the addition of us as a defendant.  The district court approved the motion to amend on November 20, 2015 and plaintiffs’ first amended complaint was filed.  Plaintiffs assert claims of negligence, violations of New Mexico’s Unfair Practices Act, and strict liability.  On December 21, 2015, we filed a motion to dismiss the New Mexico’s Unfair Practices Act and strict liability claims and, additionally, filed our answer and 12-person jury demand.  In 2014, we renewed our coverage and now maintain $200 million in liability insurance coverage for this matter.  Although we cannot predict the outcome of this matter at this point in time, we do not expect it 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 two separate water rights proceedings in the State of New Mexico that could impact the water rights for Escalante Station.  The first proceeding is an adjudication of water rights associated with Bluewater Toltec Area to determine the past, present and future use of water rights of the Pueblos of Acoma and Laguna.  The second proceeding is an application by the City of Gallup for a permit to appropriate ground water within the underground water basin near Gallup.  We are also involved in a water rights proceeding in the State of Colorado

that could impact the water rights of Burlington Generating Station.  We cannot predict the outcome of these matters, although we do not believe these proceedings are 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 4MINE 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 6SELECTED FINANCIAL DATA

The following tables set forth a summary of our consolidated financial data as of and for the years indicated.  This summary 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.

ITEM 7MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are a taxable wholesale electric power generation and transmission cooperative operating on a not‑for‑profit basis.  We are organized for the purpose of providing electricity to our 44 Members that serve major parts of Colorado, Nebraska, New Mexico and Wyoming.  We also sell a portion of our generated electric power to other utilities in the region pursuant to long‑term contracts and spot sale arrangements. Our Members provide retail electric service to rural residences, farms and ranches, cities, towns and suburban communities, as well as large and small businesses and industries. In 2015, our Members served approximately 626,000 retail electric meters over a 200,000 square‑mile area with a population of approximately 1.5 million people. In 2015, we sold 17.8 million MWhs, of which 89 percent was to Members. Total revenue from electric sales was $1.2 billion for 2015, of which 90 percent was from Member sales.

We have entered into substantially similar contracts with each Member extending through 2050 for 42 Members (which constitute approximately 95 percent of our revenue from Member sales in 2015) and extending through 2040 for the remaining two Members (Kit Carson Electric Cooperative, Inc., and Delta Montrose Electric Association, which constitute approximately 5 percent of our revenue from Member sales in 2015), and subject to automatic extension thereafter until either party provides at least a two year 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 at least 95 percent of its electric power requirements from us. Each Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled by the Member. As of December 31, 2015, 16 Members have enrolled in this program with capacity totaling approximately 79 MWs.

We provide electric power to our Members at rates established by our Board. Rates to Members are designed to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and to meet or exceed certain financial requirements. We also provide electric power to non‑members at contractual rates under long‑term arrangements and at market prices in spot sale transactions.

We are a taxable cooperative subject to federal and state taxation. As a taxable cooperative, we are allowed a tax exclusion for margins allocated to our Members as patronage capital.

Under the cooperative structure, margins represent the excess of revenues over expenses. Margins not distributed to Members in cash constitute patronage capital, a cooperative’s principal source of equity. Patronage capital is held for the account of our Members without interest and is retired when our Board deems it appropriate to do so. Our Master Indenture restricts our ability to retire patronage capital during an Event of Default (as defined in our Master Indenture). We must also satisfy the required ECR after giving effect to such retirement.  Additionally, the Board evaluates liquidity goals and equity goals (that are a part of the Board Policy for Financial Goals and Capital Credits) in determining the timing and amount of patronage capital retirement, and if the Board determines that our financial condition will not be impaired, retained patronage capital may be retired. Historically, patronage capital has been retired in order of priority according to the year in which the patronage capital was furnished and credited; however, our Bylaws were amended in 2015 to provide the Board discretion on order of retirement. As of December 31, 2015, patronage capital equity was $952.1 million.

We supply and transmit our Members’ electric power requirements through a portfolio of resources, including generating facilities, long‑term purchase contracts, and forward; short‑term and spot market energy purchases. We own, lease, have undivided percentage interests in, or have tolling arrangements with respect to, various generating facilities. Additionally, 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. See “BUSINESS - Overview- Power Supply and Transmission” for a description of miles of transmission lines and substations.

Depending on our system requirements and contractual obligations, we are likely to both purchase and sell electric power during the same fiscal period. We purchase hydroelectric power under long‑term purchase contracts.  These contracts constituted our original power resource, and they remain a cost‑effective power source. We also

purchase, under a long‑term purchase contract with Basin, the electric power needs of our Members in the state of Nebraska above our hydroelectric based power purchases there. These purchases are necessary because large portions of our Members’ loads in Nebraska are located east of the east/west electrical grid separation and are generally isolated from our facilities that are located west of the separation. These long‑term purchase commitments represent a majority of our electric power purchases. At the same time, we have agreed to supply electric power to non‑members. In addition, we utilize market purchases 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 spot market purchases during periods of generation outages at our facilities.

Critical Accounting Policies

The preparation of our financial statements in conformity with GAAP requires that our management make estimates and assumptions that affect the amounts reported in our consolidated financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. We consider the following accounting policies to be critical accounting policies due to the estimation involved or due to the particular significance they have on our consolidated financial statements.

Accounting for Rate Regulation.  We are a rate-regulated entity and, as a result, are subject to the accounting requirements of Accounting for Regulated Operations.  In accordance with these accounting requirements, some revenues and expenses have been deferred at the discretion of our Board, which has budgetary and rate‑setting authority, if it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs we expect to recover from Members based on rates approved by our Board in accordance with our rate policy. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to Members based on rates approved by our Board in accordance with our rate policy. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses concurrent with their recovery in rates.

Leases.  The accounting for lease transactions in conformity with GAAP requires management to make various assumptions, including the discount rate, the fair market value of the leased assets and the estimated useful life, in order to determine whether a lease should be classified as operating or capital. We are the lessor under power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey the right to use our power generating equipment for a stated period of time. The lease revenues from these arrangements are included in other operating revenue on our consolidated statements of operations. We are the lessee under power purchase arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey to us the right to use power generating equipment for a stated period of time. These are included in lease expense on our consolidated statements of operations.

Asset Retirement Obligations.  We account for current obligations associated with the future retirement of tangible long‑lived assets in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long‑lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long‑lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long‑lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk‑free rate including a market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. Asset retirement obligations are included in deferred credits and other liabilities.

Factors Affecting Results

Margins and Patronage Capital

We operate on a cooperative basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to meet certain financial requirements and to establish reasonable reserves. Revenues in excess of current period costs in any year are designated as net margins in our statement of operations. Net margins are treated as advances of capital by our Members and are allocated to our Members on the basis of revenue from electricity purchases from us. Net losses, should they occur, are not allocated to our Members but are offset by future margins.

Our Board Policy for Financial Goals and Capital Credits, approved and subject to change by our Board, sets guidelines to achieve margins and retain patronage capital sufficient to maintain a sound financial position and to allow for the orderly retirement of capital credits allocated to our Members. Pursuant to the policy, we target rates payable by our Members to produce financial results in excess of the requirements under our Master Indenture. On a periodic basis, our Board will determine whether to retire any patronage capital, and in what amounts, to our Members. To date, we have retired approximately $313 million of patronage capital to our Members.

Rates and Regulation

Our electric sales revenues are derived from electric power sales to our Members and non‑member purchasers.  Rates for electric power sales to our Members consist of two billing components: an energy rate and a demand rate.  Over the past five years, the average Member cents/ kWh sales, which is our total Member electric sales revenue divided by the kWhs sold has increased at an average of 2.2 percent per year.  Member rates for energy and demand are set by our Board of Directors, consistent with adequate electrical reliability and sound fiscal policy.  Energy is the physical electricity delivered through our transmission system to our Members.  In 2012, our rate schedule (A‑36 rate) had an energy rate billed based upon a price per kWh of energy delivered and a demand rate based upon our Member’s highest thirty-minute integrated total demand measured using actual metered kilowatt usage in each monthly billing period during our summer peak period or the winter peak period.  Beginning January 1, 2013, we implemented a rate design (A‑37 rate) that incorporated seasonal average demand rates.  The monthly average demand was calculated by dividing each Member’s total monthly energy (kWh) usage by the total hours in the month.  The A‑37 rate design also had an energy rate that incorporates an on-peak and off-peak period.  We developed demand response and energy shaping products to compliment the A‑37 rate schedule.  The participating Member’s monthly statements were adjusted using the demand response and energy shaping product incentives for Members utilizing those products.  Beginning January 1, 2014, the A-38 rate design went into effect.  The only change from the A-37 rate design was to implement a slight increase in the seasonal average demand rates.  In November 2014, we implemented an optional rate (TR‑1) available to our non-New Mexico Members, effective December 1, 2014 through December 31, 2015.  The TR‑1 optional rate had an energy rate billed based upon a price per kWh of energy delivered and a demand rate based upon our Member’s highest thirty-minute integrated total demand measured using the Member’s coincident peak during our peak period in each monthly billing period during our summer peak period or the winter peak period.  Three Members elected this TR-1 optional rate.  Approved by our Board of Directors in September 2015 and effective January 1, 2016, we implemented a new rate design (A‑39 rate) in which demand is billed 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 Friday, with the exception of six holidays.  Energy is billed based upon a price per kWh of energy.

Although rates established by our Board are generally not subject to regulation by federal, state or other governmental agencies, we are currently required to submit our rates to the NMPRC.  As discussed below, we are involved in a proceeding in New Mexico regarding efforts by the NMPRC related to our wholesale rates payable by our Members.  This proceeding is currently suspended for global settlement discussions.

As required by New Mexico law, we file our rates to our New Mexico Members with the NMPRC, which has regulatory authority over rate increases in New Mexico, only in the event three or more of our New Mexico Members file a request for such a review and such review is found to be qualified by the NMPRC.  In November 2012, three of our Members located in New Mexico filed protests with the NMPRC of the new A-37 wholesale rate that we filed with

the NMPRC on October 19, 2012 and which was scheduled to become effective on January 1, 2013.  The rate would have increased revenue collected from our 44 Members by approximately 4.9 percent and from our 12 New Mexico Members by approximately 6.7 percent.  On December 20, 2012, the NMPRC suspended the rate filing in New Mexico and appointed a hearing examiner to conduct a hearing and establish reasonable rate schedules pursuant to New Mexico law.  In June 2013, we attempted to withdraw the A-37 wholesale rate notice in New Mexico because our development and implementation of a new A-38 rate would likely be complete prior to NMPRC action on the suspended A-37 rate.  The NMPRC denied the filing to withdraw and ordered the A‑37 rate filing to be consolidated with the A‑38 rate filing described below.  On September 10, 2013, we gave notice, as required by New Mexico law, to the NMPRC of our new 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 and assigned the consolidated A‑37 and A‑38 rate filings to a hearing examiner.  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 (unless terminated earlier as provided in the preliminary mediation agreement) 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.  We filed notice of the temporary rate rider with the NMPRC and it became effective on October 2, 2014.  The temporary rate rider was applied in conjunction with the 2012 wholesale rate to recover additional revenue from the New Mexico Members in an annualized amount of $7 million per year, which was prorated beginning October 2 for 2014.  In 2014 and 2015, the overall impact of the New Mexico Members paying a lower rate was approximately $16.4 million and $10.7 million, respectively.  On October 9, 2015, we gave notice, as required by New Mexico law, to the NMPRC of our 2016 wholesale rate, or the A‑39 rate.  No New Mexico Member filed a protest with the NMPRC of the A‑39 rate and thus the A‑39 rate became effective on January 1, 2016 without NMPRC review or approval. 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 7, 2016, the NMPRC ordered that the procedural schedule related to the rate protests remains suspended until further order of the NMPRC.

Master Indenture

As of December 31, 2015, we had approximately $2.8 billion of secured indebtedness outstanding under our Master Indenture.  Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under our Master Indenture.

Our Master Indenture requires us to establish rates annually that are reasonably expected to achieve a DSR of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historic and pro forma basis.  Our DSR is calculated by dividing (x) our Net Margins Available for Debt Service (as defined in our Master Indenture), which is equal to our net margins for a period plus amounts deducted for the period to pay or make provision for interest on debt (including capitalized interest other than Allowance for Funds Used During Construction), lease expense, income tax expense, amortization of debt discount or premium, and depreciation and certain other non-cash items by (y) our Annual Debt Service Requirement (as defined in our Master Indenture), which is generally equal to the principal of, premium, if any, and interest (whether capitalized or expensed) on all of our debt and lease payments which become due in the applicable fiscal year or 12-month period at maturity or stated maturity, subject to special calculation rules applicable to specific types of debt (such as balloon debt). For purposes of the DSR calculation, we are permitted to exclude from the Annual Debt Service Requirement principal and interest on debt if the debt is paid or to be paid from defeasance obligations which have been irrevocably deposited or set aside in trust for payment of such debt.  Our DSR for the twelve months ended December 31, 2015 was 1.23. See Appendix A – Calculation of Financial Ratios.

Our Master Indenture also requires us to maintain an ECR at the end of each fiscal year of 14 percent through 2015, and 18 percent thereafter.  Our ECR equals our equity divided by the sum of our debt plus equity.  Equity primarily consists of our aggregate net margins that we have not distributed in cash to our Members.  Debt includes our indebtedness for borrowed money and capitalized leases but excludes indebtedness for which defeasance obligations (i.e., non-callable obligations of the United States) have been irrevocably deposited in trust.  As of December 31, 2015, our ECR was 25.1 percent. See Appendix A – Calculation of Financial Ratios.

Pursuant to the Master Indenture, DSR and ECR are calculated based on unconsolidated Tri-State financials.  Therefore, the details of the calculations are shown in Appendix A–Calculation of Financial Ratios.

Tax Status

We are a taxable cooperative subject to federal and state taxation.  As a taxable cooperative, we are allowed a tax exclusion for margins allocated as patronage capital.  We utilize the liability method of accounting for income taxes.  Accordingly, changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability.  A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.

Results of Operations

General

Our electric sales revenues are derived from electric power sales to our Members and non‑member purchasers. Rates for electric power sales to our Members consist of two billing components: an energy rate and a demand rate. See “—Factors Affecting Results – Rates and Regulation” for a description of our energy and demand rates to our Members. Long‑term contract sales to non‑members generally include energy and demand components. Spot sales to non‑members are sold at market prices after consideration of incremental production costs. Demand billings to non‑members are typically billed per kilowatt of capacity reserved or committed to that customer.

Weather has a significant effect on the usage of electricity by impacting both the electricity used per hour and the total peak demand for electricity.  Consequently, weather has a significant impact on revenues.  Relatively higher summer or lower winter temperatures tend to increase the usage of electricity for heating, air conditioning and irrigation.  Mild weather generally reduces the usage of electricity because heating, air conditioning and irrigation systems are operated less frequently.  The amount of precipitation during the growing season (generally May through September) also impacts irrigation use.  Other factors affecting our Members’ usage of electricity include:

Year ended December 31, 2015 compared to year ended December 31, 2014

Operating Revenues

Member electric sales increased 354,067 MWhs, or 2.3 percent, to 15,780,670 MWhs in 2015 compared to 15,426,603 MWhs in 2014. Member electric sales revenue increased $25.0 million, or 2.2 percent, to $1.126 billion in 2015 compared to $1.101 billion in 2014. The increase in revenue was primarily due to an increase in oil and gas loads and higher seasonal irrigation loads.

Non‑member electric sales decreased 1,245,615 MWhs, or 38.1 percent, to 2,026,525 MWhs in 2015 compared to 3,272,140 MWhs in 2014. Non-member electric sales revenue decreased $77.3 million, or 39.1 percent to $120.2 million in 2015 compared to $197.5 million in 2014. The decrease in non-member electric sales revenue was primarily due to a decrease in long-term firm energy sales to non-members of 812,880 MWhs with revenue of $41.0 million and a decrease in spot market sales of 292,768 MWhs with revenues of $12.9 million. The decrease in long-term firm energy sales to non-members was primarily due to the expiration of power sales arrangements on February 1, 2015 and September 30, 2014 that were not renewed resulting in a decrease in non-member electric sales

revenue of $37.8 million in 2015 compared to 2014. When a power generating station is initially placed into service, there is generally a period of time when sales from stations are not needed to serve our Members. In such cases, we may enter into contracts with non-members, which provide revenue to us during such periods and reduce the Member revenue requirements. We generally try to time the expiration of these contracts to coincide with forecasted increased Member demand, which had the effect of reducing non-member sales following such expirations. As a result, we determined not to renew the agreements upon their expiration. The decrease in spot market sales revenue was due to the 292,768 MWh decrease in MWhs sold and lower market prices in 2015 compared to 2014. Additionally, there was a $20.0 million decrease in non-member electric sales revenue due to the recognition in 2014 of $20.0 million of regulatory liabilities previously recorded for deferred non-member electric sales revenue and there being no such recognition in 2015. The recognition in 2014 resulted in reduced Member requirements (lower Member rates) as was required in 2014 by our Board in accordance with its budgetary and rate-setting authority.

Operating Expenses

Purchased power decreased 225,317 MWhs, or 3.1 percent, to 6,931,211 MWhs in 2015 compared to 7,156,528 MWhs in 2014. Purchased power expense decreased $22.4 million, or 6.8 percent, to $305.0 million in 2015 compared to $327.4 million in 2014 due to the decrease in MWhs purchased and a 4.4 percent decrease in the average cost per MWh of purchased power due to lower market prices for power.

Fuel expense includes coal, natural gas and other fuel consumed at the generating stations. Fuel expense decreased $61.5 million, or 21.0 percent, to $231.5 million in 2015 compared to $293.0 million in 2014. The decrease in expense was primarily due to lower coal expense resulting from the one-time $24.4 million reduction in fuel expense related to the BNSF rate transportation settlement and reduced coal consumption due to a decrease in generation of 456,404 MWhs, or 3.8 percent in 2015 compared to 2014. The largest generation decreases were Craig Station Unit 3, Escalante Station and Springerville Unit 3.

Depreciation and amortization expense increased $24.0 million, or 18.6 percent, to $152.7 million in 2015 compared to $128.7 million in 2014. The increase in expense was primarily due to additions of equipment throughout our transmission system and at our generating stations. Additionally, amortization expense increased $8.6 million in 2015 resulting from the amortization of transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized over the 21.4-year average life of the new debt issued and recovered from our Members in rates.

Other Income

Interest income decreased $6.7 million, or 60.4 percent, to $4.4 million in 2015 compared to $11.1 million in 2014. The decrease in interest income was primarily due to there being no investment during 2015 in the RUS cushion of credit, which earned a 5 percent return.

Year ended December 31, 2014 compared to year ended December 31, 2013

Operating Revenues

Member electric sales increased 113,116 MWhs to 15,426,603 MWhs in 2014 compared to 15,313,487 MWhs in 2013. The increase in MWhs sold in 2014 resulted in an increase of $10.4 million in Member electric sales revenue to $1.101 billion in 2014 compared to 2013.

Non‑member electric sales decreased 44,347 MWhs, or 1.3 percent, to 3,272,140 MWhs in 2014 compared to 3,316,487 MWhs in 2013. Despite the decrease in MWhs sold in 2014, non‑member electric sales revenue increased $25.4 million, or 14.8 percent, to $197.5 million in 2014 compared to $172.1 million in 2013. The increase in non‑member electric sales revenue in 2014 was due to the recognition of $20 million of regulatory liabilities previously recorded for deferred non‑member electric sales revenue. This recognition in 2014 resulted in reduced Member revenue requirements (lower Member rates) as was required in 2014 by our Board in accordance with its budgetary and

rate‑setting authority. The increase in non-member electric sales revenue in 2014 was also due to a 4.5 percent increase in the average price due to higher market prices, partially offset by the 1.3 percent decrease in MWhs sold for 2014.

Other operating revenue consists primarily of wheeling revenue, lease revenue, coal sales and revenue from supplying steam and water to a paper manufacturer located adjacent to the Escalante Station. Wheeling revenue is received when we charge other energy companies for transmitting electricity over our transmission lines. The lease revenue is primarily from certain power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey to others the right to use power generating equipment for a stated period of time. Coal sales revenue results from the sale of a portion of the coal from the Colowyo Mine per a contract ending in 2017 to other joint owners in the Yampa Project. Other operating revenue increased $18.1 million, or 23.2 percent, to $96.1 million in 2014 compared to $78.0 million in 2013. The increase in other operating revenue in 2014 was primarily due to an increase of $4.8 million in lease revenues resulting from the resumption of gas tolling arrangements at the Knutson and Limon Generating Stations, higher coal sales of $10.8 million as a result of delivering more coal tons in 2014 to the other joint owners in the Yampa Project and a $1.0 million transmission surcharge related to the Nucla‑Sunshine 115kv transmission project.

Operating Expenses

Purchased power increased 325,287 MWhs, or 4.8 percent, to 7,156,528 MWhs in 2014 compared to 6,831,241 MWhs in 2013. Purchased power expense increased $5.3 million, or 1.6 percent, to $327.4 million in 2014 compared to $322.1 million in 2013. The increase in expense in 2014 was due to the increase in MWhs purchased, partially offset by lower market prices for electricity.

Fuel expense includes coal, natural gas and other fuel consumed at the generating stations. Fuel expense increased $5.4 million, or 1.9 percent, to $293.0 million in 2014 compared to $287.6 million in 2013. The increase in expense for 2014 was primarily due to higher natural gas expense resulting from an increase in generation at our natural gas-fired generating stations.

Production expense includes the operation costs for the generating stations and generation maintenance expenses for maintaining the generating facilities, such as costs of scheduled maintenance outages. Production expense increased $20.1 million, or 9.6 percent, to $229.9 million in 2014 compared to $209.8 million in 2013. The increase in expense for 2014 was primarily due to higher maintenance expenses at the Escalante and J.M. Shafer Generating Stations for turbine overhaul projects and Laramie River Generating Station Unit 2 for boiler repairs and a turbine overhaul.

Transmission expense includes the operation and maintenance costs of our transmission system and wheeling expense (amounts paid for the transmission of our electricity over transmission facilities owned by other energy companies). Transmission expense increased $6.7 million, or 4.8 percent, to $145.4 million in 2014 compared to $138.7 million in 2013. The increase was primarily due to higher maintenance expense resulting from the growth in the transmission system and increased wheeling expense.

Coal mining expense includes the Colowyo Mine operating expenses related to the portion of the coal sold from the Colowyo Mine per a contract ending in 2017 to other joint owners in the Yampa Project. Coal mining expense increased $10.9 million, or 36.5 percent, to $40.8 million in 2014 compared to $29.9 million in 2013. The increase in expense for 2014 was due to higher coal mine operating expenses related to delivering more coal to the other joint owners in the Yampa Project.

Other Income

Interest income decreased $6.2 million, or 35.9 percent, to $11.1 million in 2014 compared to $17.3 million in 2013. The decrease in interest income was due to the declining investment in the RUS cushion of credit. The investment in the RUS cushion of credit was eliminated by the 2014 debt refinancing when our RUS debt and FFB debt was entirely paid off.

Interest Expense

Interest expense, net of amounts capitalized, includes the amount of interest on outstanding long-term debt less the interest charged during construction. Interest expense decreased $7.1 million, or 4.8 percent, to $142.4 million in 2014 compared to $149.5 million in 2013. The decrease in interest expense was primarily due to lower average interest rates on principal balances.

Financial Condition

Assets

Electric plant in service increased $294 million, or 5.6 percent, to $5.487 billion as of December 31, 2015 compared to $5.193 billion as of December 31, 2014. The increase was due primarily to the completion of capital improvements and system upgrades to serve the growing needs of our Members. Additionally, land and land rights increased due to the acquisition of water rights for J.M. Shafer Generating Station and renewal of right of way easements.

Other plant consists of non-utility property and the mine assets at Colowyo Mine and New Horizon Mine. Other plant increased $17.3 million, or 8.2 percent, to $228 million as of December 31, 2015 compared to $210.7 million as of December 31, 2014. The increase was primarily due to the acquisition of land and water rights in northwestern Colorado related to the Colowyo Mine and mine equipment purchases.

Cash and cash equivalents increased $52.1 million, or 56.3 percent, to $144.6 million as of December 31, 2015 compared to $92.5 million as of December 31, 2014. The increase was primarily due to $241.0 million of proceeds from issuance of debt from our Revolving Credit Agreement and an increase in cash collected from Member accounts receivable partially offset by an increase in capital expenditures and coal inventory.

Restricted cash and investments consist of (1) funds designated by our Board for specific uses, (2) funds restricted by contract or other legal reasons, and (3) investments in securities pledged as collateral in connection with the in‑substance defeasance of debt assumed in the 2011 acquisition of Colowyo Coal. The noncurrent portion of restricted cash and investments decreased $38.4 million, or 97.5 percent, to $1.0 million as of December 31, 2015 compared to $39.4 million as of December 31, 2014. The decrease was primarily due to the BNSF settlement which resolved the uncertainties related to the outcome of this matter and the $29.4 million of cash related to the BNSF settlement was no longer designated as restricted. Additionally, $8.9 million of investments in securities pledged as collateral matured in 2015. The matured U.S. Treasury Notes were used for the Colowyo Bonds principal and interest due in May and November 2015.

Coal inventory increased $18.6 million, or 45.7 percent, to $59.3 million as of December 31, 2015 compared to $40.7 million as of December 31, 2014. The increase was primarily due to a $10.6 million increase at the Craig Station as part of our coal supply planning at the station. There was also a $5.2 million increase in coal inventory at our Escalante Station and a $5.0 million increase in coal inventory at our Springerville Unit 3 due to lower generation.

Other deferred charges decreased $33.7 million, or 21.6 percent, to $122.5 million as of December 31, 2015 compared to $156.2 million as of December 31, 2014. The decrease was primarily due to $28.5 million of preliminary survey charges related to the Eastern Plains Transmission Project that was capitalized in December 2015 as part of the Burlington-Wray 230kV transmission line project.

Equity and Liabilities

Patronage capital equity increased $43.4 million, or 4.8 percent, to $952.1 million as of December 31, 2015 compared to $908.7 million as of December 31, 2014. The increase was due to a margin attributable to us of $53.4 million offset by 2015 patronage capital retirements of $10.0 million.