NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF CONSOLIDATION: Our consolidated financial statements include the accounts of the Association, our wholly‑owned and majority‑owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 12—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. The accompanying consolidated statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) as applied to regulated enterprises.

JOINTLY OWNED FACILITIES: We own undivided interests in three jointly owned generating 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). Our ownership in the San Juan Project terminated December 31, 2017. 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. See Note 3 – Property, Plant and Equipment.

SEGMENT REPORTING: We are organized for the purpose of supplying wholesale power to our Members and do so through the utilization of a portfolio of resources, including generating and transmission facilities, long‑term purchase contracts and short‑term energy purchases. In support of our coal generating resources, we have direct ownership and investments in coal mines. Our Board serves as our chief operating decision maker who manages and reviews our operating results and allocates resources as one operating segment. Therefore, we have one reportable segment for financial reporting purposes.

BUSINESS COMBINATIONS: We account for business acquisitions by applying the accounting standard related to business combinations. In accordance with this method, the identifiable assets acquired, the liabilities assumed and any noncontrolling interests in the acquired entities are required to be recognized at their acquisition date fair values. We typically engage an independent valuation firm to determine the acquisition date fair values of most of the acquired assets and assumed liabilities. The excess of total consideration transferred over the net assets acquired is recognized as goodwill. Acquisition‑related costs such as legal fees, accounting services fees and valuation fees, are expensed as incurred. We are required to consolidate these acquired entities.

If an acquisition does not result in acquiring a business, the transaction is accounted for as an acquisition of assets. This method requires measurement and recognition of the acquired net assets based upon the amount of cash transferred and the amount paid for acquisition‑related costs. There is no goodwill recognized in an acquisition of assets.

We adopted Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805) – Clarifying the Definition of a Business as of December 31, 2017, which changes the definition of a business to assist entities in evaluating whether a set of transferred assets and activities is deemed to be a business. Under this amendment, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. This amendment may result in more transactions being accounted for as asset acquisitions rather than business combinations. The adoption of this standard, which will be applied prospectively, had no impact on our consolidated financial statements.

USE OF ESTIMATES: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.

IMPAIRMENT EVALUATION: Long-lived assets (property, plant and equipment, intangible assets, investments and preliminary surveys and investigation costs) that are held and used are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. In June 2017, we determined that the $93.5 million of development costs (which excluded the costs of land and water rights) for a new coal-fired generating unit or units at Holcomb Generating Station were impaired. The impairment loss was deferred in accordance with the accounting requirements related to regulated operations at the discretion of our Board. See Note 2 – Accounting for Rate Regulation. There were no impairments of long-lived assets recognized for 2016 and 2015.

VARIABLE INTEREST ENTITIES: We evaluate our arrangements and relationships with other entities, including our investments in other associations and investments in coal mines, in accordance with the accounting standard related to consolidation of variable interest entities. This guidance requires us to identify variable interests (contractual, ownership or other financial interests) in other entities and whether any of those entities in which we have a variable interest in, meets the criteria of a variable interest entity. An entity is considered to be a variable interest entity when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making this assessment, we consider the potential that our arrangements and relationships with other entities provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of an entity, the ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that we have a variable interest in meets the criteria of a variable interest entity, we must determine whether we are the primary beneficiary of that entity. The primary beneficiary is the entity that has the power to direct the activities of the variable interest entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest entity. If we are determined to be the primary beneficiary of (has controlling financial interest in) a variable interest entity, then we would be required to consolidate that entity. In certain situations, it may be determined that power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties, then no party is the primary beneficiary. See Note 12—Variable Interest Entities.

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 we expect to recover from our Members based on rates approved by our Board in accordance with our rate policy. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Members based on rates approved by our Board in accordance with our rate policy. We recognize regulatory assets as expenses and regulatory liabilities as operating revenues, other income, or a reduction in expense concurrent with their recovery in rates.

Regulatory assets and liabilities are as follows (dollars in thousands):


	2017		2016
Regulatory assets
Deferred income tax expense (1)	$	17,205	$	30,517
Deferred prepaid lease expense – Craig Unit 3 Lease (2)		3,237		9,710
Deferred prepaid lease expense – Springerville Unit 3 Lease (3)		88,296		90,587
Goodwill – J.M. Shafer (4)		54,843		57,692
Goodwill – Colowyo Coal (5)		39,261		40,294
Deferred debt prepayment transaction costs (6)		158,187		166,815
Deferred Holcomb expansion impairment loss (7)		93,494		—
Total regulatory assets		454,523		395,615

Regulatory liabilities
Interest rate swap - unrealized gain (8)		4,311		12,140
Interest rate swap - realized gain (9)		4,614		—
Deferred revenues (10)		30,327		35,800
Membership withdrawal (11)		42,572		47,572
Total regulatory liabilities		81,824		95,512
Net regulatory asset	$	372,699	$	300,103

(1)

A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. See Note 8 – Income Taxes.

(2)

Represents deferral of the loss on acquisition related to the Craig Generating Station (“Craig Station”) Unit 3 prepaid lease expense upon acquisitions of equity interests in 2002 and 2006. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $6.5 million annually through December 31, 2017, and $3.2 million for the six month period ending June 30, 2018, and recovered from our Members in rates.

(3)

Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Members in rates.

(4)

Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP (“TCP”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Members in rates.

(5)

Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Members in rates.

(6)

Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year average life of the new debt issued and recovered from our Members in rates.

(7)

Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. On March 17, 2017, the Kansas Supreme Court issued a decision upholding the air permit for one unit at Holcomb Generating Station of 895 megawatts. The air permit expires if construction of the Holcomb expansion does not commence within 18 months. Although a final decision has not been made by our Board on whether to proceed with the construction of the Holcomb expansion, we have assessed the probability of us entering into construction for the Holcomb expansion as remote. Based on this assessment, we have determined that the costs incurred for the Holcomb expansion are impaired and not recoverable. At the discretion of our Board, the impaired loss has been deferred as a regulatory asset and will be recovered from our Members in rates. The plan for the recovery has not been determined by our Board. Once the plan for recovery is determined, the deferred impairment loss will be recognized in other operating expenses.

(8)

Represents deferral of an unrealized gain related to the change in fair value of a forward starting interest rate swap that was entered into in June 2016 in order to hedge interest rates on anticipated future borrowings. Upon settlement of this interest rate swap, the realized gain or loss will be deferred and subsequently recognized as interest expense when amortized over the term of the associated long-term debt borrowing. See Note 5 – Long-Term Debt and Note 7 – Fair Value.

(9)

Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap that was entered into in April 2016. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A. See Note 5 – Long-Term Debt.

(10)

Represents deferral of the recognition of non-member electric sales revenue. $9.2 million of this deferred revenue was recognized in non-member electric sales revenue in 2016 and $15.0 million of this deferred revenue was recognized in non-member electric sales revenue during the six months ended June 30, 2017. $9.5 million of fourth quarter 2017 non-member electric sales revenue was deferred. The balance of deferred non-member electric sales revenues of $30.3 million at December 31, 2017 will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods.

(11)

Represents deferral of the recognition of other income of $47.6 million recorded in connection with the June 30, 2016 withdrawal of Kit Carson Electric Cooperative, Inc. from membership in us. $5.0 million of this deferred membership withdrawal income was recognized in other income during the six months ended June 30, 2017. No deferred membership withdrawal income was recognized during the six month period ended December 30, 2017. The remaining deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods.

ELECTRIC PLANT AND DEPRECIATION: Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction. Interest rates charged during construction of 4.7 percent were used for 2017 and 2016 and 4.4 percent was used for 2015. The amount of interest capitalized during construction was $11.0, $13.8 and $13.5 million during 2017, 2016 and 2015, respectively. At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically re‑evaluated. See Note 3 ‑ Property, Plant and Equipment.

COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the units‑of‑production method utilizing only proven and probable reserves.

LEASES: The accounting for lease transactions in conformity with GAAP requires management to make various assumptions, including the discount rate, the fair market value of the leased assets and the estimated useful life, in order to determine whether a lease should be classified as operating or capital.

We are the lessor under a power sale arrangement that is required to be accounted for as an operating lease since the arrangement is in substance a lease because it conveys the right to use our power generating equipment for a stated period of time. The lease revenue from this arrangement is included in other operating revenue on our consolidated statements of operations. We are the lessee under a power purchase arrangement that is required to be accounted for 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. It is included in other operating expenses on our consolidated statements of operations. See Note 9 ‑ Leases.

INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include 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.

Investments in other associations are as follows (dollars in thousands):


	2017		2016
Basin Electric Power Cooperative	$	101,820	$	99,301
National Rural Utilities Cooperative Finance Corporation		27,317		26,933
CoBank, ACB		8,174		7,217
Western Fuels Association, Inc.		2,346		2,245
Other		3,951		3,654
Investments in other associations	$	143,608	$	139,350

INVESTMENTS IN AND ADVANCES TO COAL MINES: We have direct ownership and investments in coal mines to support our coal generating resources. We, and certain participants in the Yampa Project, are members of Trapper Mining, Inc. (“Trapper Mining”), which is organized as a cooperative and is the owner and operator of the Trapper Mine near Craig, Colorado. Our investment in Trapper Mining is recorded using the equity method. In addition, we have ownership in Western Fuels Association, Inc. (“WFA”), which is an owner of Western Fuels‑Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. Dry Fork Mine provides coal to MBPP, which is the operator of Laramie River Generating Station. We, through our undivided interest in the jointly owned facility MBPP, advance funds to the Dry Fork Mine.

Investments in and advances to coal mines are as follows (dollars in thousands):


	2017		2016
Investment in Trapper Mine	$	14,998	$	14,503
Advances to Dry Fork Mine		3,276		3,673
Investments in and advances to coal mines	$	18,274	$	18,176

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS: We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity.

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 are funds that have been restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on our 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 our consolidated statements of financial position.

We adopted ASU 2016-18, Statement of Cash Flows (Topic 230) – Restricted Cash as of December 31, 2017. This amendment requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.

The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands):


	2017		2016
Cash and cash equivalents	$	143,694	$	165,893
Restricted cash and investments - current		1,292		997
Restricted cash and investments - noncurrent		5,979		1,000
Cash, cash equivalents and restricted cash and investments	$	150,965	$	167,890

ASU 2016-18 was adopted using a retrospective transition method which required each comparative period to reflect the application of the amendment in our consolidated statements of cash flows. The following consolidated statements of cash flows reporting lines for the year end December 31, 2016 were affected by the adoption of this amendment:


	As		As Originally			Effect of
For the year ended December 31, 2016	Adjusted		Reported			Change
Operating activities
Adjustments to reconcile net margins to net cash provided by operating activities:
Change in restricted cash and investments	$	—	$	(137)	$	137
Other	$	(288)	$	(175)	$	(113)
Net cash provided by operating activities	$	250,812	$	250,788	$	24
Financing activities
Proceeds from investment in securities pledged as collateral	$	—	$	7,426	$	(7,426)
Other	$	(854)	$	277	$	(1,131)
Net cash used in financing activities	$	(18,283)	$	(9,726)	$	(8,557)

Net increase in cash, cash equivalents and restricted cash and investments	$	12,773	$	21,306	$	(8,533)
Cash, cash equivalents and restricted cash and investments – beginning	$	155,117	$	144,587	$	10,530
Cash, cash equivalents and restricted cash and investments – ending	$	167,890	$	165,893	$	1,997

The following consolidated statements of cash flows reporting lines for the year end December 31, 2015 were affected by the adoption of this amendment:


		As		As Originally		Effect of
For the year ended December 31, 2015		Adjusted		Reported		Change
Operating activities
Adjustments to reconcile net margins to net cash provided by operating activities:
Change in restricted cash and investments	$	—	$	29,113	$	(29,113)
Other	$	21,065	$	21,324	$	(259)
Net cash provided by operating activities	$	182,772	$	212,144	$	(29,372)
Financing activities
Proceeds from investment in securities pledged as collateral	$	—	$	8,931	$	(8,931)
Other	$	—	$	327	$	(327)
Net cash provided by financing activities	$	111,793	$	121,051	$	(9,258)

Net increase in cash, cash equivalents and restricted cash and investments	$	13,489	$	52,119	$	(38,630)
Cash, cash equivalents and restricted cash and investments – beginning	$	141,628	$	92,468	$	49,160
Cash, cash equivalents and restricted cash and investments – ending	$	155,117	$	144,587	$	10,530

The adoption of ASU 2016-18 had no impact on our consolidated statements of financial position and consolidated statements of operations.

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 securities. At December 31, 2017, the cost and estimated fair value of the investments based upon their active market value (Level 1 inputs) were $1.0 and $1.2 million, respectively, with a net unrealized gain balance of $0.2 million. At December 31, 2016, the cost and estimated fair value of the investments were $1.0 and $1.1 million, respectively, with a net unrealized gain balance of $0.1 million. The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains at December 31, 2017 and 2016 are reported as a component of accumulated other comprehensive income as of those dates. Changes in the net unrealized gains or losses are reported as a component of comprehensive income.

INVENTORIES: Coal inventories at our owned generating stations are stated at LIFO (last‑in, first‑out) cost and were $26.8 and $46.0 million as of December 31, 2017 and 2016, respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. In 2017, we realized lower coal fuel expense of $4.2 million as a result of a LIFO inventory liquidation at our generating stations.

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. Preliminary surveys and investigations were primarily comprised of development costs for the expansion at Holcomb Generating Station of $91.3 million as of December 31, 2016. There was no balance for the expansion at Holcomb Generating Station as of December 31, 2017 as a result of our determination during the second quarter of 2017 that the costs incurred for the expansion at Holcomb Generating Station were impaired. The impairment loss was deferred at the discretion of our Board. See Note 2 – Accounting for Rate Regulation.

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 Generating Station Units 1 and 2, and San Juan Project – San Juan Unit 3. Our ownership in the San Juan Project terminated December 31, 2017. We also make advance payments to the operating agent of Springerville Unit 3.

During 2016, we entered into forward starting interest rate swaps to hedge a portion of our future long-term debt interest rate exposure. One of these interest rate swaps was settled in October 2017. The realized gain of $4.6 million related to the settlement of this interest rate swap was deferred as a regulatory liability in accordance with the accounting requirements related to regulated operations. This realized gain is being amortized to interest expense over the 12-year term of the associated private placement debt issuance. The unrealized gain of $4.3 and $12.1 million as of December 31, 2017 and 2016, respectively, on the outstanding interest rate swaps was deferred in accordance with the accounting requirements related to regulated operations. See Note 2 – Accounting for Rate Regulation.

Other deferred charges are as follows (dollars in thousands):


	December 31,		December 31,
	2017		2016
Preliminary surveys and investigations	$	19,737	$	111,592
Advances to operating agents of jointly owned facilities		10,740		11,871
Interest rate swaps		4,311		12,140
Other		3,704		3,775
Total other deferred charges	$	38,492	$	139,378

DEBT ISSUANCE COSTS: We account for debt issuance costs as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Deferred debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt.

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 and 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. New Horizon Mine started final reclamation June 8, 2017.

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 generating stations.

Transmission: We had an asset retirement obligation to remove a certain transmission line and related substation assets resulting from an agreement to relocate the line. The asset retirement obligation was settled during the third quarter of 2017.

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


	2017		2016
Asset retirement obligations at beginning of period	$	58,583	$	55,215
Liabilities incurred		4,294		5,844
Liabilities settled		(4,935)		(1,298)
Accretion expense		2,623		3,751
Change in cash flow estimate		(3,710)		(4,929)
Total Asset retirement obligations at end of period	$	56,855	$	58,583
Less current asset retirement obligations at end of period		(3,087)		(6,237)
Long-term asset retirement obligations at end of period	$	53,768	$	52,346

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.

OTHER DEFERRED CREDITS AND OTHER LIABILITIES: In 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $33.4 million will be paid by us for these easements from 2017 through the individual easement terms ending between 2036 and 2040. The present value for the easement payments were $21.3 and $20.6 million as of December 31, 2017 and December 31, 2016, respectively, which is recorded as other deferred credits and other liabilities.

We received $15.5 million in 2016 from Tucson Electric Power Company (“TEP”) as ordered by the United States Federal Energy Regulatory Commission (“FERC”). In 2015, TEP filed various non-conforming point-to-point transmission services agreements with FERC, including transmission services agreements between TEP and us. FERC ordered TEP to make a time value refund to us with regard to these transmission services agreements. TEP appealed the FERC order and stated that the funds were subject to refund in the event TEP was ultimately successful in its appeal. In 2016, due to uncertainties regarding the ultimate outcome of this matter, we recorded the total receipt of $15.5 million in other deferred credits. On January 12, 2017, we entered into a settlement agreement with TEP and TEP moved to dismiss the appeal with prejudice. We returned $7.75 million to TEP and recognized $7.75 million that we retained as a reduction in transmission expense on our statement of operations during the first quarter of 2017.

We have received deposits from others for the use of optical fiber and these are reflected in unearned revenue until recognized over the life of the agreement. We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits.

The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands):


	December 31,		December 31,
	2017		2016
Transmission easements	$	21,337	$	20,562
TEP transmission refund		—		15,521
Unearned revenue		3,735		4,000
Customer deposits		2,898		3,338
Other		25,426		22,743
Total other deferred credits and other liabilities	$	53,396	$	66,164

MEMBERSHIPS: There are 43 $5 memberships outstanding at December 31, 2017 and 2016.

PATRONAGE CAPITAL: Our net margins are treated as advances of capital from our Members and are allocated to our Members on the basis of their electricity purchases from us. Net losses, should they occur, are not allocated to Members, but are offset by future margins. Margins not distributed to Members constitute patronage capital. Patronage capital is held for the account of our Members and is distributed through patronage capital retirements when our Board deems it appropriate to do so, subject to debt instrument restrictions.

ELECTRIC SALES REVENUE: Revenue from electric energy deliveries is recognized when delivered.

ACCOUNTS RECEIVABLE—MEMBERS AND OTHER: Receivables are primarily related to electric sales to Members and electric sales and other transactions with electric utilities. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible.

OTHER OPERATING REVENUE: 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. The lease revenue is primarily from a power sales arrangement that is required to be accounted for as an operating lease since the arrangement is in substance a lease because it conveys to others the right to use power generating equipment for a stated period of time. See Note 9 – Leases. Coal sales revenue results from the sale of a portion of the coal from the Colowyo Mine per a contract which ended December 31, 2017 to other joint owners in the Yampa Project (the “Yampa Participants”). The associated Colowyo Mine expenses are included in coal mining, depreciation, amortization, and depletion and interest expense on our consolidated statements of operations.

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. However, in accordance with our regulatory accounting treatment, changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. Under this regulatory accounting approach, the income tax expense (benefit) on our consolidated statements of operations includes only the current provision. See Note 8 – Income Taxes.

INTERCHANGE POWER: We occasionally engage in interchanges, or non‑cash swapping, of energy. Based on the assumption that all energy interchanged will eventually be received or delivered in‑kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange. When we are in a net energy advance position, the advanced energy balance is recorded as an asset. If we owe energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased power expense. The interchange liability balance of $1.5 and $1.9 million at December 31, 2017 and 2016, respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was $0.4 million, $0.3 million and $0.1 million in 2017, 2016 and 2015, respectively.

EVALUATION OF SUBSEQUENT EVENTS: We evaluated subsequent events through March 9, 2018, which is the date when the financial statements were issued.

NEW ACCOUNTING PRONOUNCEMENTS: In March 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715)-Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This amendment disaggregates the accounting for the service cost component of the net periodic benefit cost of an entity’s defined benefit pension and other postretirement benefit plans from the other components of the net periodic benefit cost (such as interest expense, recognition of actuarial gain or loss on postretirement benefit obligations, and amortization of prior service cost or credit). The service cost component is to be included in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. The other components of the net periodic benefit cost are to be included separately from the line item(s) that include service cost and outside of any subtotal of operating income, if one is presented. ASU 2017-07 also limits the portion of net benefit cost that is eligible for capitalization to property, plant and equipment to the current service cost component. This amendment is effective for fiscal years beginning after December 31, 2017, including interim periods within those annual periods. The guidance is required to be applied using a full retrospective transition method. We do not expect this amendment to have a material impact on our consolidated statements of operations.

In February 2016, the FASB issued ASU 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. This amendment includes an accounting policy election by class of underlying asset to exclude short-term leases. A short-term lease is defined as a lease that, at commencement date, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that the lessee is reasonably certain to exercise. 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. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842. This amendment permits an entity to elect an optional transition practical expedient to not evaluate under Topic 842 land easements that exist or that expired before the entity’s adoption of Topic 842. Once an entity adopts Topic 842, the new guidance should be applied prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2016-02, as amended by subsequent ASUs, is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The guidance is to be applied using a modified retrospective transition method with the option to elect a package of practical expedients (specifically, expired or existing contracts assessed under Topic 840 need not be reassessed, lease classification for any expired or existing leases assessed under Topic 840 need not be reassessed, and an entity need not reassess initial direct costs for any existing leases). We are currently evaluating the impact of this amendment on our consolidated statements of financial position and consolidated statements 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. This amendment requires an entity to measure investments in equity securities, except those that result in consolidation or are accounted for under the equity method of accounting, at fair value with changes in fair value recognized in net income. For equity investments that do not have readily determinable fair value and that don’t qualify for the existing practical expedient in ASC 820, Fair Value Measurements, to estimate fair value using the net asset value per share of the investment, the amendment allows entities to measure those investments at cost, less any impairment, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investment of the same issuer. This amendment also affects financial liabilities using 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 consolidated statements of financial position and consolidated statements of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as amended by subsequent ASUs issued in 2015, 2016 and 2017. The core principle under the new revenue standard requires 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, the following steps are required: (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 new standard also requires enhanced quantitative and qualitative disclosures to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

Our evaluation process of this standard includes, but is not limited to, identifying contracts within the scope of Topic 606, reviewing the contracts, and documenting our analysis of these contracts. We have evaluated our wholesale electric service contracts with our 43 Members, which was $1.2 billion, or 86.4 percent, of our total operating revenues in 2017. Revenues from electric power sales to our Members are primarily from our Class A wholesale rate schedule. Our Class A rate schedule for electric power sales to our Members consist of two billing components: an energy rate and demand rates. Our Members are billed on a monthly basis for energy consumed and demand during the period. We transfer control of the electricity over time and the Member simultaneously receives and consumes the benefits of the electricity. The amount we invoice Members on a monthly basis corresponds directly with the value to the Member of our performance. Accordingly, we do not believe there will be a material impact to our recognition of revenue from the sale of electricity to our Members.

We have evaluated the significant contracts for our non-member electric sales revenue. Our non-member electric sales revenue was $98.9 million, or 7.1 percent, of our total operating revenues in 2017. We do not believe there will be a material impact to our recognition of revenue from the sale of electricity to non-members.

We have also evaluated the impact of this new standard on our other operating revenues. Our other operating revenues were $89.8 million in 2017, or 6.5 percent, of our total operating revenues and primarily consisted of coal sales to third-parties, transmission revenue, wheeling revenue, and rent revenue from an operating lease arrangement. We do not believe there will be a material impact to our recognition of revenue from other operating revenues.

The new standard 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 where prior year results are not restated; however a cumulative-effect adjustment would be recognized in patronage capital equity at the date of adoption (January 1, 2018). We will adopt the standard using the modified retrospective transition method. While the adoption of this standard, including the cumulative-effect adjustment, is not expected to have a material impact on our consolidated financial statements, we anticipate expanded revenue disclosures related to the nature, timing, and uncertainty in revenues. We continue to evaluate the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group.

RECLASSIFICATIONS: Certain reclassifications have been made to the prior year financial statements to conform to the 2017 presentation.