UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2016

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)

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

Indicate by check mark whether the registrant has submitted electronically 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 (§232.405 of this chapter) 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 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 ☒    (Do not check if a smaller reporting company)  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 ☒

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

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2016

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10‑Q 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,” “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.  FINANCIAL INFORMATION

Item 1.  Financial Statements

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Financial Position (unaudited)

(dollars in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Operations (unaudited)

(dollars in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Comprehensive Income (unaudited)

(dollars in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Equity (unaudited)

(dollars in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Cash Flows (unaudited)

(dollars in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

Tri-State Generation and Transmission Association, Inc.

Notes to Unaudited Consolidated Financial Statements

For the Three Months Ended March 31, 2016 and 2015

NOTE 1 – PRESENTATION OF FINANCIAL INFORMATION

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. The results of operations for the three months ended March 31, 2016 and 2015 are not necessarily indicative of the results that may be expected for an entire year or any other period.

Basis of Consolidation

Our consolidated financial statements include the accounts of Tri-State Generation and Transmission Association, Inc., our wholly-owned and majority-owned subsidiaries and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 10 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. All significant intercompany balances and transactions have been eliminated in consolidation. 

Jointly Owned Facilities

We own undivided interests in three jointly owned generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us), the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)) and the San Juan Project (operated by Public Service Company of New Mexico). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and operating expenses is included in our consolidated financial statements.

Our share in each jointly owned facility is as follows as of March 31, 2016 (thousands):

NOTE 2 – ACCOUNTING FOR RATE REGULATION

We are subject to the accounting requirements related to regulated operations. In accordance with these accounting requirements, some revenues and expenses have been deferred at the discretion of our Board of Directors (“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 that we expect to recover from our member distribution systems (“Members”) through 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 our 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.

Regulatory assets and liabilities are as follows (thousands):

NOTE 3 – INVESTMENTS IN OTHER ASSOCIATIONS  

Investments in other associations includes investments in the patronage capital of other cooperatives (accounted for using the cost method) and other required investments in the organizations. Under this method, our investment in a cooperative increases when a cooperative allocates patronage capital credits to us and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. 

NOTE 4 – RESTRICTED CASH AND INVESTMENTS    

Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds is for the payment of debt within one year and funds restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on the statements of financial position. The other funds are for funds restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on the statements of financial position. 

We have investments in U.S. Treasury Notes pledged as collateral in connection with the in-substance defeasance for the principal outstanding and future interest payments on the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”). The balances in these investments are described as investments in securities pledged as collateral in the table below. As of March 31, 2016, the entire $8.6 million balance of the defeasance investment is for Colowyo Bond debt payments due within one year and is, therefore, a current asset on the consolidated statements of financial position. The Colowyo Bonds mature in November 2016.

Restricted cash and investments are as follows (thousands):

NOTE 5 – OTHER DEFERRED CHARGES  

We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Members in rates subject to approval by our Board, which has budgetary and rate-setting authority. As of March 31, 2016, preliminary surveys and investigations was primarily comprised of expenditures for the Holcomb Station Project of $88.0 million.

We make advance payments to the operating agents of jointly owned facilities. 

Other deferred charges are as follows (thousands):

NOTE 6 – LONG-TERM DEBT

The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement except for two unsecured notes in the aggregate amount of $54.2 million as of March 31, 2016. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. The Colowyo Bonds are secured by funds deposited with the trustee as part of the in-substance defeasance and an unconditional guarantee by us. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement and equity to capitalization ratio requirement. 

We have a secured revolving credit facility with Bank of America, N.A. and CoBank, ACB as Joint Lead Arrangers in the amount of $750 million (“Revolving Credit Agreement”). We had outstanding borrowings of $316 million and $271 million at March 31, 2016 and December 31, 2015, respectively. There is a 364-day, direct pay letter of credit issued under the Revolving Credit Agreement and provided by Bank of America, N.A. for the $46.8 million Moffat County, CO, Variable Rate Demand Pollution Control Revenue Refunding Bonds, Series 2009. As of March 31, 2016, we have $386 million in availability under the Revolving Credit Agreement.

Debt issuance costs are accounted for as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt.

Long-term debt consists of the following (thousands):

NOTE 7 – 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. These liabilities are included in asset retirement obligations.

Coal mines: We have asset retirement obligations for the final reclamation costs and post‑reclamation monitoring related to the Colowyo Mine, the New Horizon Mine, and the Fort Union Mine.

Fossil steam generation: We, including our undivided interest in jointly owned facilities, have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the fossil steam generating stations.

Transmission: We have an asset retirement obligation to remove a certain transmission line and related substation assets resulting from an agreement to relocate the line.

Aggregate carrying amounts of asset retirement obligations are as follows (thousands):

We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.

NOTE 8 – INCOME TAXES

We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes. 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. We had no income tax expense or benefit for the three months ended March 31, 2016 and 2015.

NOTE 9 – FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal or in the most advantageous market when no principal market exists. The fair value measurements accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows:

Level 1 inputs utilize observable market data in active markets for identical assets or liabilities.

Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity.

In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety.  The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

Marketable Securities

We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are classified as available-for-sale and are measured at fair value on a recurring basis. The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains are reported as a component of accumulated other comprehensive income. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. The carrying amounts and fair values of our marketable securities are as follows (thousands):

The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains at March 31, 2016 and December 31, 2015 are reported as a component of accumulated other comprehensive income as of those dates.

Debt

The fair values of debt were estimated using discounted cash flow analyses based on our current incremental borrowings rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs). The carrying amounts and fair values of our debt are as follows (thousands):

NOTE 10 – VARIABLE INTEREST ENTITIES

The following is a description of our financial interests in variable interest entities that we consider significant. This includes an entity for which we are determined to be the primary beneficiary and therefore consolidate and also entities for which we are not the primary beneficiary and therefore do not consolidate. 

Consolidated Variable Interest Entity

Springerville Partnership:    We own a 51 percent equity interest, including the 1 percent general partner equity interest, in the Springerville Partnership, which is the 100 percent owner of Springerville Unit 3 Holding LLC (“Owner Lessor”) of the Springerville Unit 3. We, as general partner, have the full, exclusive and complete right, power and discretion to operate, manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville Partnership in good standing without the consent of the limited partners. Additionally, the Owner Lessor has historically not demonstrated an ability to finance its activities without additional financial support. The financial support is provided by our remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership. We have the primary risk (expense) exposure in operating the Springerville Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Unit 3 and the decisions related to those expenditures including budgeting, financing and dispatch of power. Based on all these facts, it was determined that we are the primary beneficiary of the Owner Lessor. Therefore, the Springerville Partnership and Owner Lessor have been consolidated by us.    

Our consolidated statements of financial position include the Springerville Partnership’s net electric plant of $848.1 million and $853.3 million at March 31, 2016 and December 31, 2015, respectively, the long-term debt of $473.5 million and $511.0 million at March 31, 2016 and December 31, 2015, respectively, accrued interest associated with the long-term debt of $5.4 million and $14.3 million at March 31, 2016 and December 31, 2015, respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $108.8 million at March 31, 2016 and December 31, 2015.

Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $5.3 million for the three months ended March 31, 2016 and the comparable period in 2015. Our consolidated statements of operations also include interest expense of $7.7 million for the three months ended March 31, 2016 and $8.2 million for the comparable period in 2015. The net income and losses attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership are reflected on our consolidated statements of operations. The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages.

Unconsolidated Variable Interest Entities

Western Fuels Association, Inc. (“WFA”):  WFA is a non-profit membership corporation organized for the purpose of acquiring and supplying fuel resources to its members, which includes us. WFA supplies fuel to MBPP for the use of the Laramie River Station through its ownership in Western Fuels-Wyoming. We also receive coal supplies directly from WFA for the Escalante Generating Station in New Mexico and spot coal for the Springerville Unit 3 in Arizona. The pricing structure of the coal supply agreements with WFA is designed to recover the mine operating costs of the mine supplying the coal and therefore the coal sales agreements provide the financial support for the mine operations. There isn’t sufficient equity at risk for WFA to finance its activities without additional financial support. Therefore, WFA is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact WFA’s economic performance (acquiring and supplying fuel resources) is held by the members who are represented on the WFA board of directors whose actions require joint approval. Therefore, since there is shared power over the significant activities of WFA, we are not the primary beneficiary of WFA and the entity is not consolidated. Our investment in WFA, accounted for using the cost method, was $2.7 million at March 31, 2016 and $2.3 million December 31, 2015, respectively, and is included in investments in other associations.

Western Fuels – Wyoming (“WFW”):  WFW, the owner and operator of the Dry Fork Mine in Gillette, WY, was organized for the purpose of acquiring and supplying coal, through long-term coal supply agreements, to be used in the production of electric energy at the Laramie River Station (owned by the participants of MBPP) and at the Dry Fork Station (owned by Basin). WFA owns 100 percent of the class AA shares and 75 percent of the class BB shares of WFW, while the participants of MBPP (of which we have a 24.13 percent undivided interest) own the remaining 25 percent of class BB shares of WFW. The pricing structure of the coal supply agreements is designed to recover the costs of production of the Dry Fork Mine and therefore the coal supply agreements provide the financial support for the operation of the Dry Fork Mine. There isn’t sufficient equity at risk at WFW for it to finance its activities without additional financial support. Therefore, WFW is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact WFW’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the equity interest holders since each member has representation on the WFW board of directors whose actions require joint approval. Therefore, we are not the primary beneficiary of WFW and the entity is not consolidated. 

Trapper Mining, Inc. (“Trapper Mining”):  Trapper Mining is a cooperative organized for the purpose of mining, selling and delivering coal from the Trapper Mine to the Craig Generating Station Units 1 and 2 through long-term coal supply agreements. Trapper Mining is jointly owned by some of the participants of the Yampa Project.  We have a 26.57 percent cooperative member interest in Trapper Mining. The pricing structure of the coal supply agreements is designed to recover the costs of production of the Trapper Mine and therefore the coal supply agreements provide the financial support for the operation of the Trapper Mine. There isn’t sufficient equity at risk for Trapper Mining to finance its activities without the additional financial support. Therefore, Trapper Mining is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact Trapper Mining’s

economic performance (which includes operations, maintenance and reclamation activities) is shared with the cooperative members since each member has representation on the Trapper Mining board of directors whose actions require joint approval. Therefore, we are not the primary beneficiary of Trapper Mining and the entity is not consolidated. We record our investment in Trapper Mining using the equity method. Our membership interest in Trapper Mining was $14.2 million at March 31, 2016 and $14.1 million at December 31, 2015.

NOTE 11 – LEGAL

On February 17, 2016, we filed a Petition for Declaratory Order with the United States Federal Energy Regulatory Commission (‘‘FERC’’) seeking a declaratory order from FERC finding that the fixed cost recovery mechanism in our proposed revised Board policy is consistent with the provisions of Public Utility Regulatory Policies Act of 1978, as amended 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.  On March 10, 2016, we filed a supplement to our petition providing that our Board adopted the revised Board policy on March 2, 2016.  Motions to intervene or protests were due on or before March 25, 2016.  Various individuals and entities filed comments and four entities filed motions to intervene, including our Member, Delta-Montrose Electric Association (“DMEA”).  On April 8, 2016, we filed a Motion for Leave and Answer in response to motions to intervene and protests.  On April 25, 2016, DMEA filed a Motion to Answer and Answer in response to our motion. Because of the early nature of the proceedings, we are unable to project the outcome of this matter although we do not believe it is likely to have a material adverse effect on our financial condition or our future results of operations or cash flows.

NOTE 12 – NEW ACCOUNTING PRONOUNCEMENTS

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This amendment requires a lessee to recognize substantially all leases (whether operating or finance leases) on the balance sheet as a right-of-use asset and an associated lease liability. Short-term leases of 12 months or less are excluded from this amendment. A right-of-use asset represents a lessee’s right to use (control the use of) the underlying asset for the lease term. A lease liability represents a lessee’s liability to make lease payments. The right-of-use asset and the lease liability are initially measured at the present value of the lease payments over the lease term. For finance leases, the lessee subsequently recognizes interest expense and amortization of the right-of-use asset, similar to accounting for capital leases under current GAAP. For operating leases, the lessee subsequently recognizes straight-line lease expense over the life of the lease. Lessor accounting remains substantially the same as that applied under current GAAP. This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The guidance is to be applied using a modified retrospective transition method with the option to elect a package of practical expedients. We are currently evaluating the impact of this amendment on our financial position and results of operations.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.  The amendments in this ASU require that equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value, with subsequent changes in fair value recognized in net income. An entity may choose to measure equity investments that do not have readily determinable fair value at cost minus impairment. The pronouncement impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. Also, an entity should present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The amendments are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early application by public business entities to financial statements of fiscal years or interim periods that have not yet been issued or, by all other entities, that have not yet been made available for issuance are permitted as of the beginning of the fiscal year of adoption. An entity should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair values (including disclosure requirements) should be applied prospectively to equity

investments that exist as of the date of adoption of the update. We are currently evaluating the impact of this amendment on our financial position and results of operations.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements Going Concern (Subtopic 205-40); Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendment in this ASU requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern, which is currently performed by the external auditors. Management will be required to perform this assessment for both interim and annual reporting periods and must make certain disclosures if it concludes that substantial doubt exists. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meets its obligations as they become due within one year after the date that that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). The amendment is effective for annual periods, and interim periods within those annual periods, beginning on or after December 15, 2016. We are currently evaluating the impact of this amendment on our financial position and results of operations. The adoption of this update is not expected to have a material impact on the financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as amended by subsequent ASU amendments issued in 2015 and 2016. In July 2015, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. ASU 2014-09 replaces current revenue guidance, which was based on a risks and rewards model, with a transfer of control model. The core principle under the new transfer of control model states that revenue should be recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve the core principle, this amendment requires the following steps:  (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This amendment also requires additional quantitative and qualitative disclosures sufficient enough to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, this amendment is effective for the fiscal year beginning January 1, 2018 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes footnote disclosures). Reporting entities have the option to adopt the standard as early as the original January 1, 2017 effective date of this amendment. We are currently evaluating the impact of this amendment on our financial position and results of operations.

Item 2.  Management’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 member distribution systems, or 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. We sold 4.4 million megawatt hours, or MWhs, for the three months ended March 31, 2016, of which 87 percent was to Members. Total revenue from electric sales was $301.9 million for the three months ended March 31, 2016, 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 94 percent of our revenue from Member sales for the three months ended March 31, 2016) and extending through 2040 for the remaining two Members (Kit Carson Electric Cooperative, Inc., or Kit Carson, and Delta Montrose Electric Association, which constitute approximately 6 percent of our revenue from Member sales for the three months ended March 31, 2016), 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 March 31, 2016, 16 Members have enrolled in this program with capacity totaling approximately 83 megawatts.

Kit Carson has communicated its intent to withdraw from membership in us and our Board of Directors, or Board, has approved such withdrawal from membership, subject to execution of a binding agreement and compliance with certain conditions, including payment of an early termination fee. In March 2016, we executed a non-binding letter of intent with Kit Carson providing the principal terms for Kit Carson’s withdrawal. We are negotiating with Kit Carson on a binding agreement providing for Kit Carson’s withdrawal from membership in us and termination of the wholesale electric service contract with Kit Carson. For the three most recent fiscal years, Kit Carson constituted an average of approximately 2 percent of our revenue from Member sales.

We supply and transmit our Members’ electric power requirements through a portfolio of resources, including generating and transmission 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 stations. 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.

Summary of Critical Accounting Policies

As of March 31, 2016, there have been no material changes in our critical accounting policies as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015. 

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 indenture, dated effective as of December 15, 1999, or Master Indenture, between us and Wells Fargo Bank, National Association, as trustee. On a periodic basis, our Board evaluates liquidity goals and equity goals (that are a part of the Financial Goals and Capital Credits Policy) in determining the timing and amount of patronage capital retirement, and if the Board determines that our financial condition will not be impaired, a portion of 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 provide the Board with discretion on order of retirement. As of March 31, 2016, patronage capital equity was $969.6 million. 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. 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 kilowatt hour, or 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, 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.

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 New Mexico Public Regulation Commission, or NMPRC. As discussed below, we are involved in proceedings pending in New Mexico regarding efforts by the NMPRC related to our prior wholesale rates payable by our Members.

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 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. On September 10, 2013, we gave notice, as required by New Mexico law, to the NMPRC of our A-38 wholesale rate which was scheduled to become effective on January 1, 2014.  Four Members filed protests with the NMPRC challenging the A-38 rate.  The A-38 rate modified the rate design but did not increase the general revenue requirement. On December 11, 2013, the NMPRC suspended the A-38 rate filing 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 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. 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 March 31, 2016, we had approximately $2.9 billion of secured indebtedness outstanding under the Master Indenture. Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under the Master Indenture. The Master Indenture requires us to establish rates annually that are designed to maintain a Debt Service Ratio (as defined in the Master Indenture), or DSR, of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historic and pro forma basis. The Master Indenture also requires us to maintain an Equity to Capitalization Ratio (as defined in the Master Indenture) of 18 percent at the end of each fiscal year.

Tax Status

We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes. 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:

Three months ended March 31, 2016 compared to three months ended March 31, 2015

Operating Revenues

Member electric sales increased 45,747 MWhs to 3,829,433 MWhs for the three months ended March 31, 2016 compared to 3,783,686 MWhs for the same period in 2015. The increase in MWhs sold in 2016 resulted in an increase of $4.3 million in Member electric sales revenue to $271.8 million for the three months ended March 31, 2016 compared to $267.5 million for the same period in 2015. The increase in revenue was primarily due to an increase in the Members’ sales to oil and gas customers.

Non-member electric sales decreased 36,239 MWhs, or 6.1 percent, to 555,085 MWhs for the three months ended March 31, 2016 compared to 591,324 MWhs for the same period in 2015. Non-member electric sales revenue decreased $5.0 million, or 14.2 percent, to $30.1 million for the three months ended March 31, 2016 compared to $35.1 million for the same period in 2015. The decrease in non-member electric sales revenue was due to lower long-term firm energy sales to non-members of 94,323 MWhs with revenues of $4.8 million resulting from a decrease in demand for energy under these contracts due to the availability of lower priced market energy. The decrease was partially offset by an increase of 40,316 MWhs in short-term energy sales with an associated increase in revenues of $404,000.

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 Generating 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 revenue decreased $4.2 million, or 16.3 percent, to $21.6 million for the three months ended March 31, 2016 compared to $25.8 million for the same period in 2015. The decrease in other operating revenue was primarily due to a decrease in coal sales to other joint owners in the Yampa Project and a decrease in wheeling revenue, and steam and water revenue.

Operating Expenses

Purchased power increased 10,301 MWhs to 1,653,252 MWhs for the three months ended March 31, 2016 compared to 1,642,951 MWhs for the same period in 2015. Despite the increase in MWhs purchased, purchased power expense decreased $2.1 million to $71.0 million for the three months ended March 31, 2016 compared to $73.1 million for the same period in 2015 due to a 3.9 percent decrease in the average cost per MWh of purchased power resulting from lower market prices for power.

Depreciation and amortization expense increased $3.9 million, or 11.2 percent, to $38.9 million for the three months ended March 31, 2016 compared to $35.0 million for the same period in 2015. The increase in expense was primarily due to additions of equipment throughout our transmission system and at our generating stations. In addition, depreciation expense increased (beginning in the third quarter 2015) at the San Juan Generating Station Unit 3 due to a shortened economic life associated with the anticipated December 31, 2017 retirement date of the unit.

Financial condition as of March 31, 2016 compared to December 31, 2015

Assets

Cash and cash equivalents increased $16.1 million, or 11.1 percent, to $160.7 million as of March 31, 2016 compared to $144.6 million as of December 31, 2015. The increase in cash and cash equivalents was primarily due to $45 million of proceeds from issuance of debt from our secured revolving credit facility, or Revolving Credit Agreement, and an increase in cash collected from Member accounts receivable, partially offset by capital expenditures of $40.3 million, and debt payments of $41.2 million (of which $37.0 million was for a Springerville certificate payment).

Deposits and advances increased $6.8 million, or 31.3 percent, to $28.5 million as of March 31, 2016 compared to $21.7 million as of December 31, 2015. The increase was primarily due to prepayments of annual insurance, memberships and licenses. These payments are being amortized to expense over the term of the related insurance, membership or license period.

Coal inventory decreased $6.2 million, or 10.5 percent, to $53.1 million as of March 31, 2016 compared to $59.3 million as of December 31, 2015. The decrease in coal inventory was primarily due to a $5.7 million decrease in coal inventory at the Craig Generating Station and a $1.8 million decrease in coal inventory at the Springerville Generating Station Unit 3 due to coal supply planning at each station. These decreases were partially offset by a $2.2 million increase in coal inventory at our Escalante Generating Station due to lower generation.

Equity and Liabilities

Patronage capital equity increased $17.5 million to $969.6 million as of March 31, 2016 compared to $952.1 million as of December 31, 2015. The increase was due to a margin attributable to us of $17.5 million for the three months ended March 31, 2016.

Accounts payable decreased $13.8 million, or 14.4 percent, to $82.3 million as of March 31, 2016 compared to $96.1 million as of December 31, 2015. The decrease was primarily due to the timing and payment of trade payables.

Accrued interest increased $14.4 million, or 41.9 percent, to $48.7 million as of March 31, 2016 compared to $34.3 million as of December 31, 2015. The increase was primarily due to the timing of interest payments related to certain obligations that are due during the second quarter of 2016.

Liquidity

We finance our operations, working capital needs and capital expenditures from operations and issuance of debt. Our liquidity as of March 31, 2016 is as follows:

Our Revolving Credit Agreement has aggregate commitments of $750 million which includes a swingline sublimit of $100 million and a letter of credit sublimit of $200 million, of which $100 million of the swingline sublimit and $152 million of the letter of credit sublimit remained available as of March 31, 2016. The Revolving Credit Agreement is secured under the Master Indenture and has a term extending through July 26, 2019. We had outstanding borrowings of $316 million and $271 million at March 31, 2016 and December 31, 2015, respectively, and an issued letter of credit for the Moffat County, CO Pollution Control Bonds in the principal amount of $46.8 million plus accrued interest supported by the Revolving Credit Agreement. Funds advanced under the Revolving Credit Agreement bear interest either at a Eurodollar rate or a base rate, at our option.  The Eurodollar rate is the LIBOR rate for the term of the advance plus a margin (currently 1.00%) based on our credit ratings.  The base rate is the highest of (a) the federal funds rate plus ½ of 1.00%, (b) the Bank of America prime rate, and (c) the one-month LIBOR rate plus 1.00% and plus a margin (currently 0%) based on our credit ratings. As of March 31, 2016, we have $386 million in availability under the Revolving Credit Agreement.

Between projected cash on hand and the Revolving Credit Agreement, we believe we have sufficient liquidity to fund operations and capital financing needs. We anticipate establishing a commercial paper program in the second quarter of 2016.

Cash Flow

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

Operating activities.  Net cash provided by operating activities was $61.2 million for the three months ended March 31, 2016 comprised primarily of net margins of $17.6 million, non-cash depreciation, amortization, and depletion of $38.9 million, other non-cash amortization of $3.6 million and an increase in cash collected from Member accounts receivable resulting from increased loads. Operating activities were also impacted by a $15.7 million decrease in accounts payable and accrued expenses related to the timing of the payment of trade payables and an increase in accrued interest of $14.4 million due to the timing of interest payments related to certain obligations that are due during the second quarter of 2016. 

Investing activities.  Net cash used in investing activities was $45.2 million for the three months ended March 31, 2016 comprised primarily of capital expenditures for generation and transmission improvements and system upgrades.

Financing activities.  Net cash provided by financing activities was $117,000 for the three months ended March 31, 2016 comprised primarily of a $45.0 million draw on our Revolving Credit Agreement offset by payments of long-term debt of $41.2 million (principally a $37.0 million payment on the Springerville certificates).

Capital Expenditures

We forecast our capital expenditures annually as part of our long-term planning. We regularly review these projections to update our calculations to reflect changes in our future plans, facility costs, market factors and other items affecting our forecasts. 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.

Our actual capital expenditures for existing and new generating facilities and existing and new transmission facilities going forward depend on a variety of factors, including Member load growth, availability of necessary permits, current construction costs, and ability to access capital in credit markets. Thus, actual capital expenditures may vary significantly from our projections.

The majority of our capital expenditures consist of additions to electric plant and equipment. Other capital projects include several transmission projects, such as expansion in the Interstate 25 corridor north of Denver, construction of the Southwest Colorado Transmission Reliability Project, and additional projects to improve reliability and load-serving capability throughout our service area. As of March 31, 2016, we have incurred capital expenditures of approximately $88.0 million, excluding land and water purchases, in connection with the expansion project of an existing coal‑fired generating station called Holcomb Generating Station, which we refer to as Holcomb. Additional capital expenditures for Holcomb are not included in our current capital expenditure projections as our Board has not yet made a decision to proceed with the construction of this project including our option to acquire the development rights.

Contractual Commitments

Indebtedness.  As of March 31, 2016, we had approximately $2.9 billion of debt outstanding secured on a parity basis under the Master Indenture. Our debt secured by the lien of the Master Indenture includes notes payable to National Rural Utilities Cooperative Finance Corporation and CoBank, ACB (with the exception of one term loan which is unsecured), the First Mortgage Obligations, Series 2009C, the First Mortgage Bonds, Series 2010A, the First Mortgage Obligations, Series 2014B, the First Mortgage Bonds, Series 2014E-1 and E-2, the pollution control revenue bonds, and amounts outstanding under the Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Master Indenture. The Springerville certificates are secured only by a mortgage and lien on Springerville Generating Station Unit 3 and the Springerville lease.

Operating Lease Obligations.  We have a 10-year power purchase agreement with AltaGas Brush Energy, Inc. to toll natural gas at the Brush Generating Station for 70 MWs which began on October 1, 2009. We account for this power

purchase agreement as an operating lease because it conveys to us the right to use power generating equipment for a stated period of time.

Coal Purchase Obligations.  We have commitments to purchase coal for our generating stations under long-term contracts that expire between 2017 and 2034. These contracts require us to purchase a minimum quantity of coal at prices that are subject to escalation clauses that reflect cost increases incurred by the suppliers and market conditions.

Construction Obligations.  We have commitments to complete certain construction projects associated with improving the reliability of the generating stations and the transmission system.

Environmental Regulations

We are subject to various federal, state and local laws, rules and regulations with regard to air quality, including greenhouse gases, water quality, and other environmental matters.  These environmental laws, rules and regulations are complex, change frequently and have become more stringent and numerous over time.  The following are some of the recent developments relating to environmental regulations and litigation that may impact us.

Clean Power Plan.  In 2014, the Environmental Protection Agency, or 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.  Currently, our existing generating facilities generate approximately 63 percent of our energy resources, a substantial percentage of which is generated by coal-fired facilities. Emissions of carbon dioxide from our plants totaled approximately 13.0 million short tons in 2015.  The Clean Power Plan establishes guidelines for states to develop plans to limit emissions of carbon dioxide from existing units.  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 that will be submitted to the EPA by September 2016.  The EPA will take a year to review and approve state plans.  States may request an extension up to September 2018.  However, the United States 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.  If 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.  As of March 31, 2016, Nebraska, New Mexico, and Wyoming have stopped all work on the Clean Power Plan until litigation is completed.  Arizona has stopped work on modeling and plan development, but is continuing meeting on a quarterly basis.  Colorado has announced they are not developing a plan to submit to EPA but do plan to continue working on a carbon reduction plan, however, it is not clear at this time what they will actually be doing.  The EPA also proposed a federal plan that would be implemented should states fail to submit acceptable plans.  Comments on the proposed federal plan were submitted January 21, 2016.  The Clean Power Plan is the most complex and wide-ranging regulation under the Clean Air Act.  We, along with 24 states, other utilities and national trade organizations, filed motions to stay the Clean Power Plan with the United States Court of Appeals for the District of Columbia Circuit, or 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 subsequent challenges cannot be determined at this time; however if the court upholds the final rule, 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.  On October 23, 2015, the EPA also issued a final New Source Performance Standard, or NSPS, for new and modified units

that 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.

Mercury and Air Toxics Standards.  In 2012, the EPA finalized the Mercury and Air Toxics Standards, or MATS, 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 MATS rule, but the rule was upheld by the D.C. Circuit Court of Appeals in April 2014.  The United States 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 in March 2015.

In June 2015, the Supreme Court reversed the D.C. Circuit Court of Appeal’s decision and remanded the case to the D.C. Circuit Court of Appeals for further proceedings, finding that the EPA erred in refusing to consider costs when deciding whether it was appropriate and necessary to regulate emissions of hazardous air pollutants from steam electric generating units.  On December 15, 2015, the D.C. Circuit Court of Appeals remanded the proceeding to the EPA without vacatur of the MATS rule.  On April 15, 2016, the Administrator signed EPA’s final supplemental notice in response to the Supreme Court's remand of the MATS rule.  As in the proposed version, EPA finds that it is appropriate and necessary to regulate hazard air pollutant emissions from electric generating utilities under section 112 of the Clean Air Act, even after considering costs.  We are in full compliance with the rule’s emission limits, which required new emission controls on Craig Generating Station Unit 3, Springerville Generating Station Unit 3, Escalante Generating 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.  The Nucla Generating Station currently meets all compliance aspects of the MATS rule.

For further discussion regarding potential effects on our business from environmental regulations, see “Item 1 – BUSINESS — ENVIRONMENTAL REGULATION” and “Item 1A — Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015.

Tucson Electric Power Company, or TEP, FERC Case

In 2015, TEP filed various non-conforming point-to-point transmission services agreements with the United States Federal Energy Regulatory Commission, or FERC, including transmission services agreements between TEP and us.  FERC, in 2015, ordered TEP to refund the time value of monies for a certain period of time with regard to these transmission services agreements between TEP and us. TEP subsequently requested rehearing with FERC. On April 21, 2016, FERC denied TEP’s request for rehearing regarding these transmission services agreements between TEP and us and ordered TEP to make a time value refund within 30 days of the date of the order, including an amount up to $12.8 million to us. We expect TEP to appeal FERC’s order.

Rating Triggers

Our current senior secured ratings are “A3 (stable outlook)” by Moody’s Investors Services, “A (stable outlook)” by Standard & Poor’s Ratings Services, and “A (stable outlook)” by Fitch Rating Inc.

The Revolving Credit Agreement includes a pricing grid related to the LIBOR spread, commitment fee and letter of credit fees due under the facility.  A downgrade of our ratings could result in an increase in each of these pricing components.  We do not believe that any such increase would be significant or have a material adverse effect on our financial condition or our future results of operations.

We currently have contracts that require adequate assurance of performance.  These include power sales arrangements that are required to be accounted for as operating leases, natural gas supply contracts and financial risk management contracts.  Some of the contracts are directly tied to our credit rating being maintained at “BBB-” or better from S&P or “Baa3” from Moody’s.  We expect to enter into additional natural gas supply contracts and/or risk management contracts which will contain similar adequate assurance requirements.  If we are required to provide such adequate assurances, we

do not believe the amounts will be significant or that they will have a material adverse effect on our financial condition or our future results of operations.

Off Balance Sheet Arrangements – Purchase Power Agreements Accounted for as Leases

We have a 10-year purchase power agreement with AltaGas Brush Energy, Inc. to toll natural gas at the Brush Generating Station for 70 MWs which began on October 1, 2009. We account for this power purchase agreement as an operating lease since the arrangement is in substance a lease because it conveys to us the right to use power generating equipment for a stated period of time.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

There have not been any material changes to market risks during the most recent fiscal quarter from those reported in our Annual Report on Form 10-K for the year ended December 31, 2015.

On April 13, 2016, we entered into a 36 month forward-starting 30 year LIBOR swap in the notional amount of $90 million with an effective date of April 15, 2019 and a maturity date of April 15, 2049.  The fixed rate on the swap is 2.355%.  We entered into the interest rate derivative transaction to partially hedge exposure to changes in long-term interest rates for forecasted debt issuances.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

Changes in Internal Controls

There have been no changes in our internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Information required by this Item is contained in the Notes to Unaudited Consolidated Financial Statements within Part I of this Form 10-Q in Note 11 - Legal.

Item 4.  Mine Safety Disclosures

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

Item 6.  Exhibits

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.