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 June 30, 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. 333-212006

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

(Exact name of registrant as specified in its charter)

(303) 452-6111

(Registrant’s telephone number, including area code)

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 has not been subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) for the past 90 days. 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 JUNE 30, 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

(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 and Six Months Ended June 30, 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 and six months ended June 30, 2016 and 2015 are not necessarily indicative of the results that may be expected for an entire year or any other period.

On June 30, 2016, Kit Carson Electric Cooperative, Inc. (“KCEC”) withdrew from membership in us pursuant to the Membership Withdrawal Agreement (“Withdrawal Agreement”). The Withdrawal Agreement provided for the termination of the wholesale electric service contract between us and KCEC that extended through 2040 and the withdrawal of KCEC from membership in us. As part of the Withdrawal Agreement, we received $37 million net cash, which consists of $49.5 million as an early termination fee for withdrawing from membership in us offset by $12.5 million for the retirement of KCEC’s patronage capital. This resulted in $47.6 million in other income, which was deferred by our Board of Directors (“Board”) and is recorded in deferred credits and other liabilities on the statement of financial position. For each of the three most recent fiscal years and the six months ended June 30, 2016, KCEC constituted an average of approximately 2 percent of our revenue from our member distribution system (“Member”) sales.

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 11 – 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 June 30, 2016 (dollars in 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, 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 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 (dollars in 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 consolidated 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 consolidated 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 June 30, 2016, the entire $3.8 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 (dollars in 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 June 30, 2016, preliminary surveys and investigations was primarily comprised of expenditures for the Holcomb Station Project of $89.1 million.

We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, Yampa Project – Craig Station Units 1 and 2, San Juan Project – San Juan Unit 3. We also make advance payments to the operating agent of Springerville Unit 3. 

Other deferred charges are as follows (dollars in 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 $52.6 million as of June 30, 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”) that expires on July 26, 2019. We had no outstanding borrowings at June 30, 2016 and $271 million at December 31, 2015. 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.

On May 23, 2016, we issued our First Mortgage Bonds, Series 2016A (“Series 2016A Bonds”) in an unregistered offering pursuant to Rule 144A under the Securities Act of 1933 with an aggregate principal amount of $250 million. The Series 2016A Bonds mature on June 1, 2046 and bear interest at a rate of 4.25 percent per annum. We utilized the

proceeds from the Series 2016A Bonds primarily to repay outstanding indebtedness under the Revolving Credit Agreement. In connection with the Series 2016A Bonds, we entered into an exchange and registration rights agreement pursuant to which we agreed to file a registration statement relating to an exchange offer for our Series 2016A Bonds. On June 27, 2016, we commenced an offer to exchange all of the unregistered $250 million aggregate principal amount of the Series 2016A Bonds for $250 million aggregate principal amount of registered Series 2016A Bonds. We completed the exchange offer in July 2016 which satisfied our obligations under the exchange and registration rights agreement. The exchange offer did not represent a new financing transaction and there were no proceeds to us when the exchange offer was completed.

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 (dollars in thousands):

We are exposed to certain risks in the normal course of operations in providing a reliable and affordable source of wholesale electricity to our Members. These risks include interest rate risk, which represents the risk of increased operating expenses and higher rates due to increases in interest rates related to anticipated future long-term borrowings. To manage this exposure, we have entered into forward starting interest rate swaps to hedge a portion of our future long-term debt interest rate exposure. We anticipate settling these swaps in conjunction with the issuance of future long-term debt. See Note 2 – Accounting for Rate Regulation and Note 10 – Fair Value.

The terms of the interest rate swap contracts are as follows (dollars in thousands):

NOTE 7 – SHORT-TERM BORROWINGS   

Commercial Paper

We established a commercial paper program in May 2016 under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper sublimit under our Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our Revolving Credit Agreement. The commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary, but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on the consolidated statements of financial position.

Commercial paper consisted of the following (dollars in thousands):

NOTE 8 – 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 (dollars in 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 9 – 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. Income tax expense was $350,000 for the three and six months ended June 30, 2016 and there was no income tax expense or benefit for the three and six months ended June 30, 2015.

NOTE 10 – 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 are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities.

Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models, discounted cash flow models) for which all significant assumptions are observable in the market.

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 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 are reported as a component of accumulated other comprehensive income. The amortized cost and fair values of our marketable securities are as follows (dollars in thousands):

Cash Equivalents

We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $49.1 million as of June 30, 2016 and $75.1 million as of December 31, 2015, respectively.

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 (dollars in thousands):

Interest Rate Swaps

We have entered into forward starting interest rate swaps to hedge a portion of our future long-term debt interest rate expense. These interest rate swaps are derivative instruments in accordance with ASC 815, Derivatives and Hedging, and are recorded at fair value on a recurring basis. The estimated fair value of these interest rate swaps utilizes 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) and is included in other deferred credits and other liabilities on our consolidated statements of financial position. At June 30, 2016, the fair value of our interest rate swaps was $12.6 million.

NOTE 11 – 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 $842.8 million and $853.3 million at June 30, 2016 and December 31, 2015, respectively, the long-term debt of $473.1 million and $511.0 million at June 30, 2016 and December 31, 2015, respectively, accrued interest associated with the long-term debt of $13.4 million and $14.3 million at June 30, 2016 and December 31, 2015, respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $108.9 million and $108.8 million at June 30, 2016 and December 31, 2015, respectively.

Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $5.3 million for the three months ended June 30, 2016 and the comparable period in 2015. Our consolidated statements of operations also include interest expense of $7.6 million for the three months ended June 30, 2016 and $8.0 million for the comparable period in 2015. Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization of $10.5 million for the six months ended June 30, 2016 and the comparable period in 2015. Our consolidated statements of operations also include interest expense of $15.3 million for the six months ended June 30, 2016 and $16.2 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 June 30, 2016 and $2.3 million at 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 $14.3 million at June 30, 2016 and $14.1 million at December 31, 2015.

NOTE 12 – 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 revised Board policy provides for recovery of the unrecovered fixed costs directly from that Member as a result of that Member purchasing power from a “qualifying facility” in an amount that causes it to exceed the 5 percent limitation on that Member’s self-supply of power pursuant to its wholesale electric service contract, rather than allocating the costs among all of our Members. The fixed cost recovery is calculated based on the difference between our wholesale rate to our Members and our avoided costs. On June 16, 2016, FERC denied our Petition for Declaratory Order related to the fixed cost recovery mechanism in our revised Board policy.  On July 18, 2016, we filed a Request for Rehearing with FERC regarding FERC’s June 16 order. In addition, five other generation and transmission cooperatives have filed a Request for Rehearing with FERC. We are evaluating the impact of FERC’s denial and cannot predict the outcome of our July 18 request for rehearing filed with FERC.

NOTE 13 – NEW ACCOUNTING PRONOUNCEMENTS

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 362). The amendment requires that financial assets measured at amortized cost be presented net of expected credit losses. The expected credit loss reflects management’s current estimate of credit losses that are expected to occur over the remaining life of a financial asset. This is in contrast to existing guidance whereby credit losses generally are not recognized until they are incurred. This amendment is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted. The guidance is applied using a modified retrospective transition method. We are currently evaluating the impact that the standard will have on our financial position and results of operations.

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 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. 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 member distribution systems, or Members, that serve major parts of Colorado, Nebraska, New Mexico and Wyoming. We currently have 43 Members after the withdrawal in June 2016 of Kit Carson Electric Cooperative, Inc., or KCEC, from membership in us. 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. As of June 30, 2016, our 43 Members served approximately 600,000 retail electric meters over a nearly 200,000 square-mile area. We sold 8.8 million megawatt hours, or MWhs, for the six months ended June 30, 2016, of which 86.7 percent was to Members. Total revenue from electric sales was $604.1 million for the six months ended June 30, 2016, of which 90.6 percent was from Member sales.

We have entered into substantially similar wholesale electric service contracts with each Member extending through 2050 for 42 Members (which constitute approximately 94.5 percent of our revenue from Member sales for the six months ended June 30, 2016) and extending through 2040 for the remaining Member (Delta Montrose Electric Association, which constitutes approximately 3.6 percent of our revenue from Member sales for the six months ended June 30, 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 June 30, 2016, after the withdrawal of KCEC from membership in us, 16 Members have enrolled in this program with capacity totaling approximately 95 megawatts.

On June 30, 2016, KCEC withdrew from membership in us pursuant to the Membership Withdrawal Agreement, or Withdrawal Agreement. The Withdrawal Agreement provided for the termination of the wholesale electric service contract between us and KCEC that extended through 2040 and the withdrawal of KCEC from membership in us. As part of the Withdrawal Agreement, we received $37 million net cash, which consists of $49.5 million as an early termination fee for withdrawing from membership in us offset by $12.5 million for the retirement of KCEC’s patronage capital. This resulted in $47.6 million in other income, which was deferred by our Board of Directors, or Board, and is recorded in deferred credits and other liabilities on the statement of financial position. For each of the three most recent fiscal years and the six months ended June 30, 2016, KCEC 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 June 30, 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 June 30, 2016, patronage capital equity was $959.7 million. To date, we have retired approximately $325.5 million of patronage capital to our Members, including the $12.5 million we retired as part of KCEC’s withdrawal from membership in us.

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 2012, three of our New Mexico Members filed protests with the NMPRC of our A-37 wholesale rate that we filed with the NMPRC and which was scheduled to become effective on January 1, 2013. 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 2013, four of our New Mexico Members filed protests with the NMPRC of our A-38 wholesale rate that we filed with the NMPRC and was scheduled to become effective on January 1, 2014. The NMPRC suspended the A-38 rate filing and assigned the consolidated A-37 and A-38 rate filings to a hearing examiner. In 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. In 2015, we gave notice, as required by New Mexico law, to the NMPRC of our A-39 wholesale 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. In December 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. In January 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 June 30, 2016, we had approximately $2.8 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 June 30, 2016 compared to three months ended June 30, 2015

Operating Revenues

Member electric sales increased 145,247 MWhs, or 4.0 percent, to 3,770,267 MWhs for the three months ended June 30, 2016 compared to 3,625,020 MWhs for the same period in 2015. The increase in MWhs sold in 2016 resulted in an increase of $18.2 million, or 7.1 percent, in Member electric sales revenue to $275.5 million for the three months ended June 30, 2016 compared to $257.3 million for the same period in 2015. The increase in revenue was primarily due to continued operation of large gas processing loads that came on line during the third and fourth quarter of 2015 and residential growth along the Front Range.

Non-member electric sales increased 64,699 MWhs, or 11.9 percent, to 610,787 MWhs for the three months ended June 30, 2016 compared to 546,088 MWhs for the same period in 2015. Non-member electric sales revenue decreased $3.1 million, or 10.4 percent, to $26.7 million for the three months ended June 30, 2016 compared to $29.8 million for the same period in 2015. The increase of 64,699 MWhs was comprised of an increase of 109,051 MWhs of short-term non-member sales and a decrease of 44,352 MWhs in long-term firm sales to non-members due to the expiration of several higher priced long-term power sales arrangements on December 31, 2015 and March 31, 2016 that were not renewed. The decrease in long-term firm sales resulted in a decrease in non-member revenue of $2.9 million. Although short-term non-member sales increased (which were made at spot market prices that are lower than the firm sales) revenue associated with such sales decreased by $206,000 due to a decrease in spot market rates in 2016 as compared to 2015.

Operating Expenses

Purchased power increased 244,383 MWhs, or 15.0 percent, to 1,870,722 MWhs for the three months ended June 30, 2016 compared to 1,626,339 MWhs for the same period in 2015. Purchased power expense increased $6.9 million, or 9.7 percent, to $78.2 million for the three months ended June 30, 2016 compared to $71.3 million for the same period in 2015. The increase in expense was primarily due to the increase in MWhs purchased partially offset by a 5.0 percent decrease in the average cost per MWh of purchased power resulting from lower market prices for power.

Fuel expense includes coal, natural gas and other fuel consumed at the generating stations. Fuel expense increased $16.0 million, or 44.9 percent, to $51.6 million for the three months ended June 30, 2016 compared to $35.6 million for the same period in 2015. The increase in expense was primarily due to higher coal expense at our Craig Generating Station resulting from an increase in generation and lower coal expense in the second quarter of 2015 resulting from the one-time recognition of $24.4 million as a reduction to fuel expense because of the BNSF rate settlement. The effect of the BNSF rate settlement was partially offset by lower coal expense at our Nucla Generating Station due to a planned outage.

Production expense decreased $13.4 million, or 19.0 percent, to $57.0 million for the three months ended June 30, 2016 compared to $70.4 million for the same period in 2015. The decrease in expense was primarily due to a decrease in maintenance outages in 2016 (generation maintenance expense was higher in 2015 than in 2016 due to scheduled generation maintenance expenses incurred in 2015 at our Craig Generating Station and Laramie River Station).

Depreciation and amortization expense increased $5.9 million, or 16.4 percent, to $41.9 million for the three months ended June 30, 2016 compared to $36.0 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.

Six months ended June 30, 2016 compared to six months ended June 30, 2015

Operating Revenues

Member electric sales increased 190,994 MWhs, or 2.6 percent, to 7,599,700 MWhs for the six months ended June 30, 2016 compared to 7,408,706 MWhs for the same period in 2015. The increase in MWhs sold in 2016 resulted in an increase of $22.5 million, or 4.3 percent, in Member electric sales revenue to $547.3 million for the six months ended June 30, 2016 compared to $524.8 million for the same period in 2015. The increase in revenue was primarily due to continued operation of large gas processing loads that came on line during the third and fourth quarter of 2015 and residential growth along the Front Range.

Non-member electric sales increased 28,460 MWhs, or 2.5 percent, to 1,165,872 MWhs for the six months ended June 30, 2016 compared to 1,137,412 MWhs for the same period in 2015. Non-member electric sales revenue decreased $8.1 million, or 12.4 percent, to $56.8 million for the six months ended June 30, 2016 compared to $64.9 million for the same period in 2015 despite the increase in MWhs. The increase of 28,460 MWhs was comprised of an increase of 167,135 MWhs of short-term non-member sales and a decrease of 138,675 MWhs in long-term firm sales to non-members due to the expiration of several higher priced long-term power sales arrangements on December 31, 2015 and March 31, 2016 that were not renewed. The decrease in long-term firm sales resulted in a decrease in non-member revenue of $7.7 million. Although short-term non-member sales increased (which were made at spot market prices that are lower than the firm sales) revenue associated with such sales decreased by $348,000 due to a decrease in spot market rates in 2016 as compared to 2015.

Other operating revenue consists primarily of wheeling, transmission, and lease revenues, 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. Transmission revenue is from our membership in the Southwest Power Pool, a regional transmission organization which began on January 1, 2016. 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 $3.0 million, or 6.7 percent, to $41.6 million for the six months ended June 30, 2016 compared to $44.6 million for the same period in 2015. The decrease in other operating revenue was primarily due to a $2.6 million decrease in coal sales to other joint owners in the Yampa Project, a $3.6 million decrease in lease revenue due to the expiration of power sales arrangements at our Knutson and Limon Generating Stations, and a $442,000 decrease in steam and water revenue. These decreases in other revenue were partially offset by a $3.5 million increase in transmission revenue resulting from our membership in the Southwest Power Pool.

Operating Expenses

Fuel expense increased $15.8 million, or 16.2 percent, to $112.6 million for the six months ended June 30, 2016 compared to $96.8 million for the same period in 2015. The increase in expense was primarily due to lower coal expense in the second quarter of 2015 resulting from the one-time recognition of $24.4 million as a reduction to fuel expense because of the BNSF rate settlement. The effect of the BNSF rate settlement was partially offset by fewer coal deliveries and planned maintenance outages.

Production expense decreased $15.9 million, or 12.8 percent, to $108.0 million for the six months ended June 30, 2016 compared to $123.9 million for the same period in 2015. The decrease in expense was primarily due to a decrease in maintenance outages in 2016 (generation maintenance expense was higher in 2015 than in 2016 due to scheduled generation maintenance expenses incurred in 2015 at our Craig Generating Station and Laramie River Station).

Depreciation and amortization expense increased $9.9 million, or 13.9 percent, to $80.8 million for the six months ended June 30, 2016 compared to $70.9 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 June 30, 2016 compared to December 31, 2015

Assets

Construction work in progress decreased $38.8 million, or 17.9 percent, to $177.5 million as of June 30, 2016 compared to $216.3 million as of December 31, 2015. The decrease was primarily due to transfers to electric plant in service for completed projects of $118.8 million (the largest project was completion of the Burlington-Wray 230 KV transmission line of $56.5 million) offset by capital expenditures of $82.0 million related to various generation and transmission capital improvements and system upgrades.

Cash and cash equivalents increased $14.2 million, or 9.8 percent, to $158.8 million as of June 30, 2016 compared to $144.6 million as of December 31, 2015. The increase in cash and cash equivalents was primarily due to $248.0 million of proceeds from the issuance of the First Mortgage Bonds, Series 2016A, or Series 2016A Bonds, $62.0 million of proceeds from our secured revolving credit facility, or Revolving Credit Agreement, and $234.9 million of proceeds from the issuance of commercial paper. Additionally, cash increased as a result of receiving $37.0 million of net cash related to the withdrawal of KCEC from membership in us. Partially offsetting these increases in cash were debt payments of $408.6 million (principally $333.0 million on our Revolving Credit Agreement, $27.1 million on the First Mortgage Obligations, Series 2009C, $37.0 million on the Springerville certificates and $4.5 million on the Colowyo Bonds) and $140 million of commercial paper payments (maturities).

Restricted cash and investments consist of funds designated by our Board for specific uses and funds restricted by contract or other legal reasons and investments in securities pledged as collateral in connection with the in-substance defeasance of debt assumed in the 2011 acquisition of Colowyo Coal. Restricted cash and investments decreased $4.8 million, or 45.8 percent, to $5.7 million as of June 30, 2016 compared to $10.5 million as of December 31, 2015. The decrease was primarily due to $4.6 million of investment in securities pledged as collateral associated with debt that matured during the second quarter of 2016.

Deposits and advances increased $10.5 million, or 48.4 percent, to $32.2 million as of June 30, 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.

Other deferred charges increased $9.6 million, or 7.8 percent, to $132.1 million as of June 30, 2016 compared to $122.5 million as of December 31, 2015. The increase was primarily due to an increase of $7.8 million related to advance payments to the operating agents of jointly owned facilities and Springerville Unit 3 to fund our share of operational costs and capital projects expected to be incurred under each project. Also, there was an increase in expenditures of $1.7 million related to preliminary surveys, plans, and investigations (primarily for the Holcomb project).

Equity and Liabilities