Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | ||
Entity Registrant Name | CHUGACH ELECTRIC ASSOCIATION INC | |
Entity Filer Category | Non-accelerated Filer | |
Entity Central Index Key | 878,004 | |
Entity Voluntary Filers | Yes | |
Entity Well-known Seasoned Issuer | No | |
Entity Current Reporting Status | No | |
Amendment Flag | false | |
Document Type | 10-K | |
Document Fiscal Period Focus | FY | |
Document Period End Date | Dec. 31, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Current Fiscal Year End Date | --12-31 | |
Entity Common Stock, Shares Outstanding | 0 | |
Entity Public Float | $ 0 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Utility plant: | ||
Electric plant in service | $ 1,205,092,224 | $ 1,192,513,869 |
Construction work in progress | 17,952,573 | 18,455,940 |
Total utility plant | 1,223,044,797 | 1,210,969,809 |
Less accumulated depreciation | (515,496,312) | (496,098,131) |
Net utility plant | 707,548,485 | 714,871,678 |
Other property and investments, at cost: | ||
Nonutility property | 76,889 | 76,889 |
Investments in associated organizations | 8,980,410 | 9,349,311 |
Special funds | 1,466,010 | 907,836 |
Restricted cash equivalents | 1,028,758 | 810,559 |
Investments - other | 0 | 3,061,434 |
Total other property and investments | 11,552,067 | 14,206,029 |
Current assets: | ||
Cash and cash equivalents | 5,485,631 | 4,672,935 |
Special deposits | 54,300 | 75,942 |
Restricted cash equivalents | 687,370 | 899,723 |
Marketable securities | 11,420,900 | 7,375,381 |
Fuel cost under-recovery | 4,921,794 | 0 |
Accounts receivable, less provisions for doubtful accounts of $555,336 in 2017 and $484,352 in 2016 | 35,680,680 | 33,000,919 |
Materials and supplies | 15,291,095 | 27,889,167 |
Fuel stock | 6,901,994 | 6,321,676 |
Prepayments | 4,953,170 | 1,407,026 |
Other current assets | 257,193 | 294,697 |
Total current assets | 85,654,127 | 81,937,466 |
Other non-current assets: | ||
Deferred charges, net | 32,764,065 | 25,140,957 |
Total other non-current assets | 32,764,065 | 25,140,957 |
Total assets | 837,518,744 | 836,156,130 |
Equities and margins: | ||
Memberships | 1,719,154 | 1,691,014 |
Patronage capital | 172,928,887 | 169,996,436 |
Other | 14,653,253 | 13,828,075 |
Total equities and margins | 189,301,294 | 185,515,525 |
Long-term obligations, excluding current installments: | ||
Bonds payable | 421,833,331 | 405,249,998 |
Notes payable | 37,164,000 | 40,356,000 |
Less unamortized debt issuance costs | (2,669,485) | (2,715,745) |
Total long-term obligations | 456,327,846 | 442,890,253 |
Current liabilities: | ||
Current installments of long-term obligations | 26,608,667 | 24,836,667 |
Commercial paper | 50,000,000 | 68,200,000 |
Accounts payable | 7,420,279 | 9,618,630 |
Consumer deposits | 5,335,896 | 5,207,585 |
Fuel cost over-recovery | 0 | 3,824,722 |
Accrued interest | 5,991,619 | 5,873,368 |
Salaries, wages and benefits | 7,017,131 | 7,315,898 |
Fuel | 9,913,781 | 6,284,338 |
Other current liabilities | 7,079,821 | 3,234,586 |
Total current liabilities | 119,367,194 | 134,395,794 |
Other non-current liabilities: | ||
Deferred compensation | 1,229,294 | 907,836 |
Other liabilities, non-current | 531,630 | 655,277 |
Deferred liabilities | 1,249,390 | 1,179,414 |
Patronage capital payable | 8,798,077 | 12,008,499 |
Cost of removal obligation / asset retirement obligation | 60,714,019 | 58,603,532 |
Total other non-current liabilities | 72,522,410 | 73,354,558 |
Total liabilities, equities and margins | $ 837,518,744 | $ 836,156,130 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Consolidated Balance Sheets [Abstract] | ||
Accounts receivable, provision for doubtful accounts | $ 555,336 | $ 484,352 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Consolidated Statements Of Operations [Abstract] | |||
Operating revenues | $ 224,688,669 | $ 197,747,579 | $ 216,421,152 |
Operating expenses: | |||
Fuel | 78,552,672 | 54,778,582 | 66,534,877 |
Production | 18,006,490 | 15,809,168 | 16,886,257 |
Purchased power | 17,301,067 | 15,774,733 | 19,599,994 |
Transmission | 6,129,871 | 5,590,737 | 6,287,558 |
Distribution | 13,991,088 | 13,991,997 | 14,089,862 |
Consumer accounts | 5,968,736 | 6,073,710 | 6,117,625 |
Administrative, general and other | 23,256,983 | 22,888,048 | 23,623,299 |
Depreciation and amortization | 34,010,777 | 36,233,414 | 35,652,086 |
Total operating expenses | 197,217,684 | 171,140,389 | 188,791,558 |
Interest expense: | |||
Long-term debt and other | 22,366,034 | 21,856,095 | 22,194,290 |
Charged to construction | (164,898) | (454,798) | (379,845) |
Interest expense, net | 22,201,136 | 21,401,297 | 21,814,445 |
Net operating margins | 5,269,849 | 5,205,893 | 5,815,149 |
Nonoperating margins: | |||
Interest income | 644,663 | 425,173 | 296,788 |
Allowance for funds used during construction | 69,157 | 188,111 | 142,881 |
Capital credits, patronage dividends and other | 65,055 | (5,321) | 248,034 |
Total nonoperating margins | 778,875 | 607,963 | 687,703 |
Assignable margins | $ 6,048,724 | $ 5,813,856 | $ 6,502,852 |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Equities And Margins - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Balance | $ 185,515,525 | $ 181,637,381 | $ 185,515,525 | $ 181,637,381 | $ 176,925,299 | ||
Assignable margins | $ 4,738,734 | 4,261,642 | $ 5,632,088 | 2,628,930 | 6,048,724 | 5,813,856 | 6,502,852 |
Retirement/net transfer of capital credits | (3,116,273) | (3,265,201) | (3,190,124) | ||||
Unclaimed capital credit retirements | 612,752 | 1,175,962 | 1,298,410 | ||||
Memberships and donations received | 240,566 | 153,527 | 100,944 | ||||
Balance | 189,301,294 | 185,515,525 | 189,301,294 | 185,515,525 | 181,637,381 | ||
Memberships [Member] | |||||||
Balance | 1,691,014 | 1,661,744 | 1,691,014 | 1,661,744 | 1,631,569 | ||
Assignable margins | 0 | 0 | 0 | ||||
Retirement/net transfer of capital credits | 0 | 0 | 0 | ||||
Unclaimed capital credit retirements | 0 | 0 | 0 | ||||
Memberships and donations received | 28,140 | 29,270 | 30,175 | ||||
Balance | 1,719,154 | 1,691,014 | 1,719,154 | 1,691,014 | 1,661,744 | ||
Other Equities And Margins [Member] | |||||||
Balance | 13,828,075 | 12,527,856 | 13,828,075 | 12,527,856 | 11,158,677 | ||
Assignable margins | 0 | 0 | 0 | ||||
Retirement/net transfer of capital credits | 0 | 0 | 0 | ||||
Unclaimed capital credit retirements | 612,752 | 1,175,962 | 1,298,410 | ||||
Memberships and donations received | 212,426 | 124,257 | 70,769 | ||||
Balance | 14,653,253 | 13,828,075 | 14,653,253 | 13,828,075 | 12,527,856 | ||
Patronage Capital [Member] | |||||||
Balance | $ 169,996,436 | $ 167,447,781 | 169,996,436 | 167,447,781 | 164,135,053 | ||
Assignable margins | 6,048,724 | 5,813,856 | 6,502,852 | ||||
Retirement/net transfer of capital credits | (3,116,273) | (3,265,201) | (3,190,124) | ||||
Unclaimed capital credit retirements | 0 | 0 | 0 | ||||
Memberships and donations received | 0 | 0 | 0 | ||||
Balance | $ 172,928,887 | $ 169,996,436 | $ 172,928,887 | $ 169,996,436 | $ 167,447,781 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | |||
Assignable margins | $ 6,048,724 | $ 5,813,856 | $ 6,502,852 |
Adjustments to reconcile assignable margins to net cash provided by operating activities: | |||
Depreciation and amortization | 34,010,777 | 36,233,414 | 35,652,086 |
Amortization and depreciation cleared to operating expenses | 4,791,978 | 4,988,068 | 4,390,385 |
Allowance for funds used during construction | (69,157) | (188,111) | (142,881) |
Write off of inventory, deferred charges and projects | 413,690 | 997,301 | 691,035 |
Other | 27,986 | 248,482 | (220,496) |
(Increase) decrease in assets: | |||
Accounts receivable, net | (2,858,099) | (4,926,631) | 6,866,956 |
Fuel cost under-recovery | (4,921,794) | 0 | 0 |
Materials and supplies | 896,455 | (850,493) | (1,070,896) |
Fuel stock | (580,318) | 741,865 | 2,588,532 |
Prepayments | (3,546,144) | 59,275 | 712,422 |
Other assets | 59,146 | (71,144) | 215,738 |
Deferred charges | (201,775) | (10,374,429) | (405,746) |
Increase (decrease) in liabilities: | |||
Accounts payable | (1,469,106) | 750,538 | (270,416) |
Consumer deposits | 128,311 | 206,901 | 86,424 |
Fuel cost over-recovery | (3,824,722) | (1,311,023) | 3,673,688 |
Accrued interest | 118,251 | (42,212) | (276,028) |
Salaries, wages and benefits | (298,767) | 56,092 | (287,510) |
Fuel | 3,629,443 | 1,342,028 | (6,195,299) |
Other current liabilities | (2,045,800) | (1,051,220) | (290,715) |
Deferred liabilities | (17,927) | (128,221) | (123,695) |
Net cash provided by operating activities | 30,291,152 | 32,494,336 | 52,096,436 |
Cash flows from investing activities: | |||
Return of capital from investment in associated organizations | 370,010 | 319,233 | 352,420 |
Investment in restricted cash equivalents | (5,846) | (1,398) | (1,141) |
Investment in special funds | (236,716) | 0 | 0 |
Investment in marketable securitiesand investments-other | (924,903) | (10,580,000) | 0 |
Investment in Beluga River Unit | 0 | (44,403,922) | 0 |
Proceeds from restricted cash equivalents | 0 | 1,140,343 | 0 |
Proceeds from capital grants | 115,453 | 1,021,929 | 2,395,331 |
Extension and replacement of plant | (28,879,926) | (36,984,892) | (35,094,355) |
Net cash used in investing activities | (29,561,928) | (89,488,707) | (32,347,745) |
Cash flows from financing activities: | |||
Payments for debt issue costs | (206,871) | (277,155) | 0 |
Net increase (decrease) in short-term obligations | (18,200,000) | 48,200,000 | (1,000,000) |
Proceeds from long-term obligations | 40,000,000 | 45,600,000 | 0 |
Repayments of long-term obligations | (24,836,667) | (48,181,832) | (23,889,777) |
Memberships and donations received | 853,318 | 1,329,489 | 357,365 |
Retirement of patronage capital and estate payments | (2,258,047) | (4,378,853) | (182,352) |
Net receipts on consumer advances for construction | 4,731,739 | 3,748,738 | 4,228,030 |
Net cash provided by (used in) financing activities | 83,472 | 46,040,387 | (20,486,734) |
Net change in cash and cash equivalents | 812,696 | (10,953,984) | (738,043) |
Cash and cash equivalents at beginning of period | 4,672,935 | 15,626,919 | 16,364,962 |
Cash and cash equivalents at end of period | 5,485,631 | 4,672,935 | 15,626,919 |
Supplemental disclosure of non-cash investing and financing activities: | |||
Cost of removal obligation | 2,110,487 | 3,008,808 | 1,366,318 |
Asset retirement obligation assumed upon BRU acquisition | 0 | 3,523,409 | 0 |
Extension and replacement of plant included in accounts payable | 1,185,788 | 1,915,033 | 2,582,947 |
Patronage capital retired/net transferred and included in other current liabilities | 2,057,036 | 0 | 2,105,440 |
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized | $ 20,911,535 | $ 20,220,317 | $ 21,891,308 |
Description Of Business
Description Of Business | 12 Months Ended |
Dec. 31, 2017 | |
Description Of Business [Abstract] | |
Description Of Business | (1) Description of Business Chugach Electric Association, Inc. (Chugach) is one of the largest electric utilities in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity in the Anchorage and upper Kenai Peninsula areas. Chugach is on an interconnected regional electrical system referred to as the Alaska Railbelt, a 400 -mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska's largest cities, Anchorage and Fairbanks. Chugach’s retail and wholesale members are the consumers of the electricity sold. Chugach supplies much of the power requirements to the City of Seward (Sew ard), as a wholesale customer. Chugach also served Matanuska Electric Association, Inc. (MEA) thro ugh their contract expiration on April 30, 2015 . Through March 31, 2015 , we sold economy (non-firm) energy to Golden Valley Electric Association, Inc. (GVEA) , which used that energy to serve its own load. Periodically, Chugach sells available generation, in excess of its own needs, to MEA, Homer Electric Association, Inc. (HEA), GVEA and Anchorage Municipal Light & Power (ML&P). Chugach was organized as an Alaska electric cooperative in 1948 and operates on a not ‑for ‑profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reserves. Chugach is subject to the authority of the Regulatory Commission of Alaska (RCA). The consolidated financial statements include the activity of Chugach and the activity of the Beluga River Unit (BRU). Chugach accounts for its share of BRU activity using proportional consolidation (see Note 15 – “Beluga River Unit” ). Intercompany activity has been eliminated for presentation of the consolidated financial statements. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Significant Accounting Policies [Abstract] | |
Significant Accounting Policies | (2) Significant Accounting Policies a. Management Estimates In preparing the financial statements in conformity with United States generally accepted accounting principles (GAAP), the management of Chugach is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Estimates include the allowance for doubtful accounts, workers’ compensation liability, deferred charges and liabilities, unbilled revenue, estimated useful life of utility plant, cost of removal and asset retirement obligation (ARO), and remaining proved BRU reserves. Actual results could differ from those estimates. b. Regulation The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.” FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. Our regulated rates are established to recover all of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings and our rates, see Note (2o ) – “ Defer red Charges and Liabilities .” c. Utility Plant and Depreciation Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, removal cost, less salvage, is charged to accumulated depreciation . Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred. In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain asset groups are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset group may not be recoverable in rates. Recoverability of asset groups to be held and used is measured by a comparison of the carrying amount of an asset group to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset group exceeds the fair value of the asset. Depreciation and amortization rates have been applied on a straight ‑line basis and at December 31, 2017 are as follows: Annual Depreciation Rate Ranges Six months ending June 30, 2017 Six months ending December 31, 2017 Steam production plant 3.15% - 3.84% 3.03% - 3.26% Hydroelectric production plant 1.06% - 3.00% 0.88% - 2.71% Other production plant 3.15% - 8.85% 2.18% - 3.46% Transmission plant 1.58% - 7.86% 1.01% - 10.50% Distribution plant 2.16% - 9.63% 1.40% - 10.00% General plant 1.57% - 20.00% 1.95% - 33.33% Other 2.75% - 2.75% 2.75% - 2.75% On March 23, 2017, the RCA approved revised depre ciation rates effective July 1, 2017 in Docket U-16-081(2) . Chugach’s depreciation rates include a provision for cost of removal. Chugach records a separate liability for the estimated obligation related to the cost of removal. Chugach records Depreciation, Depletion and Amortization (DD&A) expense on the BRU assets based on units of production using the following formula: ten percent of the total production from the BRU as provided by the operator divided by ten percent of the estimated remaining proved reserves (in thousand cubic feet (Mcf)) in the field multiplied by Chugach’s total assets in the BRU. d. Full Cost Method Pursuant to FASB ASC 932-360-25, “Extractive Activities-Oil and Gas – Property, Pla nt and Equipment – Recognition,” Chugach has elected the Full C ost method, rather than the Successful Efforts method, to account for exploration and development costs of gas reserves. e. Asset Retirement Obligation (ARO) Chugach calculated and recorded an Asset Retirement Obligation associated with the BRU. Chugach uses its BRU financing rate as its credit adjusted risk free rate and the expected cash flow approach to calculate the fair value of the ARO liability. The ARO asset is depreciated using the DD&A formula previously discussed. The ARO liability is accreted using the interest method of allocation. f. Investments in Associated Organizations The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is less than one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 201 7 , 201 6 or 201 5 . g. Investments – Other Inv estments – other cons ists of certificates of deposit with a maturity greater than 12 months. Total investments – other were $3.1 million as of December 31, 2016 . h. Special Funds Special funds includes deposits associated with the deferred compensation plan and an investment associated with the BRU ARO. The BRU ARO investment was established pursuant to an agreement with the State of Alaska and was $0.2 million as of December 31, 2017. i . Cash and Cash Equivalents / Restricted Cash Equivalents For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has a concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. The concentration account had an average balance of $6,454,809 and $5,897,767 during the years ended December 31, 201 7 and 201 6 , respectively. Restricted cash equivalents include funds on deposit for future workers’ compensation claims . Total current and long term restricted cash equivalents were $1.7 million at December 31, 201 7 and 201 6 . j . Marketable Securities Chugach’s marketable securities consist of bond mutual funds , corporate bonds, and certificates of deposit with a maturity less than 12 months, classified as trading securities, reported at fair value with gains and losses in earnings. Net gains on marketable securities are included in nonoperating margins – capital credits, patronage dividends and othe r, and are summarized as follows: Twelve months ended December 31, 2017 Net gains and losses recognized during the period on trading securities $ 59,182 Less: Net gains and losses recognized during the period on trading securities sold during the period 0 Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date $ 59,182 k . Accounts Receivable Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receiv able are invoiced amounts to ML&P for their proportionate share of current Southcentral Power Project ( SPP ) costs, which amounted to $1.3 million and $1.4 million in 201 7 and 201 6 , respectively. At December 31, 2017 and 2016 , accounts receivable also included $ 1.1 million and $0.7 million, respectively, from BRU operations primarily associated with gas sales to ENSTAR. l . Materials and Supplies Materials and supplies are stated at average cost. m . Fuel Stock Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natu ral Gas Storage Alaska (CINGSA) . Chugach’s fuel balance in storage for the years ended December 31, 201 7 and 201 6 amounted to $ 6 . 9 million and $6.3 million, respectively. n . Fuel and Purchased Power Cost Recovery Expenses associated with electric services include fuel purchased from others and produced from Chugach’s interest in the BRU, both of which are used to generate electricity, as well as power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel and purchased power adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under- or over-collection of fuel and purchased power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. o . Deferred Charges and Liabilities Included in deferred charges and liabilities on Chugach’s financial statements are regulatory assets and liabilities recorded in accordance with FASB ASC 980 . See Note 8 – Deferred Charges and Liabilities . Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. Chugach’s regulatory asset recoveries are embedded in base rates approved by the RCA. Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard Simplified Rate Filings (SRF), general rate case filings or specified independent requests. The rates approved related to the regulatory assets are matched to the amortization of actual expenses recognized. The regulatory assets are amortized and collected through rates over differing periods depending upon the period of benefit as established by the RCA. Deferred liabilities include refundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construct ion are held in deferred liabilities pending their return or other disposition. If events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on Chugach’s financial position, results of operations or cash flows. On December 29, 2016, Chugach made a prepayment of $7.9 million to the National Rural Electric Cooperative Association (NRECA) Retirement and Security (RS) Plan, which is included in deferred charges. Chugach recorded the long term prepayment in deferred charges and is amortizing the deferred charge to administrative, general and other expense, over 11 years, which represents the difference between the normal retirement age of 62 and the average age of Chuga ch’s employees in the RS Plan. The balance of the prepayment in deferred charges at December 31, 2017 and 2016 was $ 7.2 million and $7.9 million, respectively . p . Patronage Capital Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach’s statement of operations as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors (Board). Retained assignable margins are designated on Chugach’s balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board may also approve the return of capital to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September of 2002. q . Consumer Deposits Consumer deposits include amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 201 7 and 201 6 , totaled $3.7 million and $3.3 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.6 million and $1.9 million for the years ended December 31, 2017 and 2016. r . Fair Value of Financial Instruments FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments: Cash and cash equivalents – the carrying amount approximates fair value because of the short maturity of those instruments. Restricted cash – the carrying amount approximates fair value because of the short maturity of those instruments. Marketable securities – the carrying amount approximates fair value as changes in the market value are recorded monthly and gains or losses are reported in earnings (see note 2 j and note 4). Long ‑term obligations – the fair value estimate is based on the quoted market price for same or similar issues (see note 11). Consumer deposits – the carrying amount approximates fair value because of the short refunding term. The fair value of accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature. s . Operating Revenues Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,674,543 and $10,940,274 of unbilled retail reven ue at December 31, 2017 and 2016 , respectively , which is included in accounts receivable on the balance sheet . Wholesale revenue is recorded from metered locations on a calendar month basis, so no estimation is required. Chugach's tariffs include provisions for the recovery of gas costs according to gas supply contracts, as well as purchased power costs. t . Capitalized Interest Allowance for funds used during construction (AFUDC) and interest charged to construction ‑ credit (IDC) are the estimated costs of the funds used during the period of construction from both equity and borrowed funds. AFUDC and IDC are applied to specific projects during construction. AFUDC and IDC calculations use the net cost of borrowed funds when used and is recovered through RCA approved rates as utility plant is depreciated. For all projects Chugach capitalized such funds at the weighted average rate of 4.1% during 201 7 and 4.3 % during 201 6 and 201 5 . u . Environmental Remediation Costs Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset. v . Income Taxes Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 201 7 , 201 6 and 201 5 was in compliance with that provision. In addition, as described in Note (16 ) – “Commitments and Contingencies,” Chugach collects sales tax and is assessed gross revenue and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.” Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties. FASB ASC 740, “Topic 740 – Income Taxes,” only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding or retroactive tax positions that were not highly certain of being sustained upon examination by the taxing authorities. Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 201 5 through December 31, 201 7 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 201 7 . w . Grants Chugach has received federal and state grants to offset storm related expenditures and to support investigating means of mitigating the impact of renewable generation variability on the grid as well as the construction of facilities to transport fuel, divert water and safely transmit electricity to its consumers. Grant proceeds used to construct or acquire equipment are offset against the carrying amount of the related assets while grant proceeds for storm related expenditures are offset again st the actual expense incurred. Chugach received no grants in 2017 and $0.6 million in 2016. |
Accounting Pronouncements
Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Pronouncements [Abstract] | |
Accounting Pronouncements | (3) Accounting Pronouncements Issued, not yet adopted: ASC Update 2014-09 “Revenue from Contracts with Customers (Topic 606)” and Related Updates In May of 2014, the FASB issued ASC Update 2014-09, “Revenue from Contracts with Customers (Topic 606).” ASC Update 2014-09 provides guidance for the recognition, measurement and disclosure of revenue related to the transfer of promised goods or services to customers. Chugach adopted the standard on January 1, 2018 using the modified retrospective transition method with an immaterial cumulative effect adjustment as of the January 1, 2018 adoption date. We have evaluated our energy sales contracts, including retail, wholesale, and economy energy, and do not b elieve there will be an impact to the timing or pattern of revenue recognition from our energy sales. Energy sales are billed monthly per regulator approved tariffs based on the energy consumed by the customer. Total revenue derived from energy sales during 2017 was approximately 99% of our total operating revenue. The adoption of Topic 606 also includes additional disclosure requirements beginning in the first quarter of 2018, including expanded disclosures around the amount, timing, nature and uncertainty of revenues from contracts with customers. We are finalizing the required disclosures. ASC Update 2016-01 “ Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities ” In January of 2016, the FASB issued ASC Update 2016-01, “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” ASC Update 2016-01 amends guidance related to certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2018, and interim periods beginning after December 15, 2019, with early adoption not permitted with certain exceptions. Chugach will begin application of ASC 2016-01 with the annual report for the year ended December 31, 2019 . Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2016-02 “ Leases (Topic 842): Section A – Leases: Amendments to the FASB Accounting Standards Codification; Section B – Conforming Amendments Related to Leases: Amendments to the FASB Accounting Standards Codification; Section C – Background Information and Basis for Conclusions ” In February of 2016, the FASB issued ASC Update 2016-02, “Leases (Topic 842): Section A – Leases: Amendments to the FASB Accounting Standards Codification; Section B – Conforming Amendments Related to Leases: Amendments to the FASB Accounting Standards Codification; Section C – Background Information and Basis for Conclusions.” ASC Update 2016-02 amends guidance related to the recognition, measurement, presentation and disclosure of leases for lessors and lessees. This update is effective for fiscal years beginning after December 15, 2018, including the interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-02 on January 1, 2019. Chugach expects this update to increase the recorded amounts of assets and liabilities and we are evaluating the significance of the increase. We are also evaluating the impact of this update to our results of operations, financial position, and cash flows. ASC Update 2016-13 “ Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ” In June 2016, the FASB issued ASC Update 2016-13, “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” ASC Update 2016-13 revised the criteria for the measurement, recognition, and reporting of credit losses on financial instruments to be recognized when expected. This update is effective for fiscal years beginning after December 15, 2019, including the interim periods within those years, with early adoption permitted for fiscal years beginning after December 15, 2018, including interim periods within those years. Chugach will begin application of ASC 2016-13 on January 1, 2020. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2016-15 “ Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force )” In August 2016, the FASB issued ASC Update 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). ASC Update 2016-15 clarifies how certain cash payments and cash proceeds should be classified on the statement of cash flows to limit the diversity in practice. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-15 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2016-18 “ Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) ” In November 2016, the FASB issued ASC Update 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” ASC Update 2016-18 clarifies how to classify and present changes in restricted cash or cash equivalents that occur when there are transfers between cash, cash equivalents, and restricted cash or restricted cash equivalents and when there are direct cash receipts into or payments made from restricted cash or restricted cash equivalents on the statement of cash flows to limit the diversity in practice. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-18 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2017-01 “ Business Combinations (Topic 805): Clarifying the Definition of a Business ” In January 2017, the FASB issued ASC Update 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” ASC Update 2017-01 clarifies the definition of a business by providing a screen to determine when a set of assets and activities acquired or disposed of constitute a business, as well as a framework for evaluating whether all elements of a business are present in the set. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted only when the transaction has not been reported in financial statements. Chugach will begin application of ASC 2017-01 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2017-07 “ Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ” In March 2017, the FASB issued ASC Update 2017-07, “Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” ASC Update 2017-07 amends current guidance on the presentation and disclosure of other compensation costs in the income statement. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted only for financial statements that have not been issued. Chugach will begin application of ASC 2017-07 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” In January 2018, the FASB issued ASC Update 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842.” ASC Update 2018-01 amends current guidance to provide an optional transition practical expedient allowing entities to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. This update is effective for fiscal years beginning after December 15, 2018, including the interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2018-01 on January 1, 2019. Chugach is evaluating the impact of the Lease update as well as existing land easements to determine if we will elect to use the practical expedient for transition as well as the effect on our results of operations, financial position, and cash flows. |
Fair Value Of Assets And Liabil
Fair Value Of Assets And Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Of Assets And Liabilities [Abstract] | |
Fair Value Of Assets And Liabilities | (4) Fair Value of Assets and Liabilities Fair Value Hierarchy In accordance with FASB ASC 820, Chugach groups its financial assets and liabilities measured at fair value in three levels, based on the markets in which the assets and liabilities are traded and the reliability of the assumptions used to determine fair value. These levels are: Level 1 – Valuation is based upon quoted prices for identical instruments traded in active exchange markets, such as the New York Stock Exchange. Level 1 also includes United States Treasury and federal agency securities, which are traded by dealers or brokers in active markets. Valuations are obtained from readily available pricing sources for market transactions involving identical assets or liabilities. Level 2 – Valuation is 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 for which all significant assumptions are observable in the market. Level 3 – Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect Chugach’s estimates of assumptions that market participants would use in pricing the asset or liability. Valuation techniques include use of option pricing models, discounted cash flow models and similar techniques. The table below presents the balance of Chugach’s marketable securities measured at fair value on a recurring basis at December 31, 2017 and 2016 . Chugach’s bond mutual funds , corporate bonds , and marketable certificates of deposit are measured using quoted prices in active markets. Chugach had no other assets or liabilities measured at fair value on a recurring basis at December 31, 2017 or 201 6 . December 31, 2017 Total Level 1 Level 2 Level 3 Bond mutual funds $ 8,109,242 $ 8,109,242 $ 0 $ 0 Corporate bonds $ 248,335 $ 248,335 $ 0 $ 0 Certificates of deposit $ 3,063,323 $ 3,063,323 $ 0 $ 0 December 31, 2016 Total Level 1 Level 2 Level 3 Bond mutual funds $ 7,375,381 $ 7,375,381 $ 0 $ 0 Certificates of deposit $ 3,061,434 $ 3,061,434 $ 0 $ 0 Fair Value of Financial Instruments Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. The fair value of cash and cash equivalents, accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature. The estimated fair values (in thousands) of long-term obligations included in the financial statements at December 31, 2017 , are as follows: Carrying Value Fair Value Level 2 Long-term obligations (including current installments) $ 485,606 $ 511,196 |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Matters [Abstract] | |
Regulatory Matters | (5) Regulatory Matters Amended Eklutna Generation Station 2015 Dispatch Services Agreement On February 13, 2015, Chugach submitted the Amended Eklutna Generation Station 2015 Dispatch Services Agreement (Dispatch Services Agreement) to the RCA for dispatch services to be provided by Chugach to MEA for a one -year period. Under the Dispatch Services Agreement, Chugach provides electric and natural gas dispatch services for MEA’s Eklutna Generation Station (EGS), electric dispatch services for the Bradley Lake Hydroelectric Project (Bradley Lake), and electric dispatch coordination services for the Eklutna Hydroelectric Project (Eklutna Hydro) beginning with EGS’ full commercial operation. On March 23, 2015, the RCA approved the Dispatch Agreement, conditioned on the requirements that: 1) MEA and Chugach notify the RCA at least one month prior to forming separate Load Balancing Authorities and include in any such notification details on the tie points and any written agreements contemplated by the utilities; and, 2) Chugach file an update to its tariff to reflect any extension of the Dispatch Services Agreement one week from the receipt of such a request from MEA. The Dispatch Services Agreement was in effect through March 31, 2016 . In December of 2015, MEA notified Chugach that it would not be extending the Dispatch Services Agreement for the dispatch of electric service. Subsequently, Chugach and MEA entered into an agreement entitled, “Gas Dispatch Agreement” in which Chugach provides gas scheduling and dispatch services to MEA. The term of the agreement was April 1, 2016 , through March 31, 2017 . On April 18, 2016, Chugach requested RCA approval of the special contract. The RCA issued a letter order on June 8, 2016, approving the filing. Chugach and MEA signed an agreement to extend the gas dispatch agreement through March 31, 2018, and later signed an amendment to extend the agreement through March 31, 2019. A letter order was issued by the RCA on September 22, 2017 , approving the amendment to the agreement to extend gas dispatch services as filed in Tariff Advice No. 442-8. Simplified Rate Filing Chugach is a participant in the Simplified Rate Filing (SRF) process for adjustments to base demand and energy rates for Chugach retail customers and wholesale customer, Seward. SRF is an expedited base rate adjustment process available to electric cooperatives in the State of Alaska, with filings made either on a quarterly or semi-annual basis. Chugach is a participant on a quarterly filing schedule basis. Chugach submitted quarterly SRF filings which resulted in a 3.0% decrease to system demand and energy rates effective July 1, 2017 , and an increase of 1.9 % for rates effective November 1, 2017 . The SRF based on the September 2017 test year resulted in a 0.4 % increase to system demand and energy rates effective February 1, 2018 . Furie Agreement On March 16, 2017, Chugach submitted a request to the RCA for approval of the agreement entitled, “Firm and Interruptible Gas Sale and Purchase Agreement between Furie Operating Alaska, LLC and Chugach Electric Association, Inc.” (Furie Agreement) dated March 3, 2017. As part of the filing, Chugach also requested RCA approval to recover both firm and interruptible purchases under the agreement and all attendant transportation and storage costs through its quarterly fuel and purchased power cost adjustment process. The Furie Agreement provides Chugach with both firm and non-firm gas supplies over a 16 -year period, with firm purchases beginning on April 1, 2023 , and ending on March 31, 2033 , and interruptible gas purchases available to Chugach immediately and ending on March 31, 2033. With respect to firm purchases beginning on April 1, 2023, and ending on March 31, 2033, the Furie Agreement provides an annual gas commitment by Furie to sell and Chugach to purchase approximately 1.8 Bcf of gas each year, which represents approximately 20% to 25 % of Chugach’s projected gas requirements during this period. The Furie Agreement also provides Chugach with additional purchase options, on a firm and interruptible basis. The initial price for firm gas is $7.16 per Mcf beginning April 1, 2023 and escalates annually rising to $ 7.98 per Mcf on April 1, 2032, the last year of the Furie Agreement. On May 1, 2017, the RCA approved the Furie Agreement. The RCA also approved recovery of costs associated with the Furie Agreement through its fuel and purchased power cost adjustment process. Beluga River Unit Gas Transfer Price On June 29, 2016, Chugach filed a petition with the RCA for approval to create a regulatory asset for the deferral of expenses (financial/economic, engineering and legal services) associated with Chugach’s acquisition of the BRU, which was $1.5 million at December 31, 2016, and is included in deferred charges on Chugach’s balance sheet. See Note 8 – Deferred Charges and Liabilities . Chugach also requested approval to recover the deferred costs in the gas transfer price. On September 14, 2016, the RCA issued an order combining the BRU cost recovery process and the request to create a regulatory asset into a single docket. The RCA established a procedural schedule and indicated that a final order in the case would be issued by November 17, 2017. Docket U-16-062 / U-16-074 was established to address the creation of a regulatory asset for the recovery of costs associated with Chugach’s acquisition of a portion of ConocoPhillips Alaska, Inc.’s interest in the BRU and to determine the methodology to establish permanent rates for the gas transfer price (GTP) associated with Chugach’s ownership interest in the BRU. On September 7, 2017, the RCA issued U-16-062(7) / U-16-074(7) accepting a stipulation between Chugach and the Office of the Attorney General Regulatory Affairs and Public Advocacy Section and vacating the procedural hearing. On October 7, 2017, Chugach submitted the BRU GTP calculations to the RCA as part of a compliance filing to the settlement. On October 26, 2017, the RCA issued a final order accepting Chugach’s compliance filing and closing the docket. Beluga Parts Filing On November 18, 2016, Chugach submitted a petition to the RCA for approval to create a regulatory asset that would allow Chugach to amortize and recover in rates the value of certain plant needed to support power production equipment located at the Beluga Power Plant. Specifically, Chugach requested RCA approval to recover approximately $11.4 million in equipment that supports Beluga generation units. Chugach requested that it be permitted to amortize the value of this plant over a period of 30 months for plant associated with Units 1 and 2 (approximately $0.3 million), and 108 months for all other parts (approximately $11.1 million). The amortization periods are consistent with the proposed depreciation rates for the Beluga units contained in Chugach’s depreciation study that was submitted to the RCA on September 30, 2016. The RCA opened Docket Number U-16-092 to review the petition. The RCA approved the petition May 17, 2017 closing docket U-16-092(2). Depreciation Study Update In compliance with a previous order from the RCA (U-12-009(8)), Chugach submitted a 2015 Depreciation Study Update to the RCA, requesting approval of the depreciation rates resulting from the study for use in Chugach’s financial record keeping and for establishing electric rates. The filing was submitted to the RCA on September 30, 2016. Chugach proposed changes to depreciation rates that would result in a $5.9 million reduction in annual depreciation expense. On a demand and energy rate basis, the impact was a 4.7% reduction to retail customers and a 4.6% reduction to Seward. The reductions on a total customer bill basis, which includes fue l and purchased power costs, were 3.2% and 1.9% , respectively. Chugach requested that the updated depreciation rates be implemented on July 1, 2017, for both accounting and ratemaking purposes. On March 23, 2017, the RCA issued Order U-16-081(2) approving Chugach’s proposed changes to its depreciation rates. The depreciation rates were approved as filed. The RCA required Chugach to file a new depreciation study by July 1, 2022, based on plant activity as of December 31, 2021. Cook Inlet Natural Gas Alaska: Found Gas On January 30, 2015, CINGSA submitted a filing to the RCA providing notice that it had found 14.5 Bcf of gas as a result of directional drilling in the storage facility and proposed to establish guidelines for commercial sales of at least 2 Bcf of this gas. Chugach submitted comments to the RCA regarding CINGSA’s proposed trea tment of found gas. Chugach did not believe CINGSA’s proposal to retain revenues for the sale of found gas should be permitted in recognition of the risk-sharing agreements made by CINGSA and its storage customers that resulted in the development of the CINGSA storage facility. The RCA issued an order in March of 2015 , suspending the filing for further investigation. CINGSA filed direct testimony in the case on April 13, 2015. Chugach and other interveners in the case submitted responsive testimony on June 5, 2015. CINGSA submitted its reply testimony on June 29, 2015. The evidentiary hearing was held in September of 2015. The RCA issued a final order in the case on December 4, 2015, ruling significantly in favor of the interveners in the case. The RCA granted approval for CINGSA to sell 2 Bcf with 87% of the proceeds allocated to CINGSA’s Firm Storage Service (FSS) customers and 13 percent to CINGSA. The RCA also required CINGSA to file a reservoir engineering study by June 30, 2016, and required CINGSA to file notice of all gas sales within 30 days of any sales, including the transaction price, purchaser, quantities, and the terms and conditions of the sale. The RCA also required that all proceeds to the FSS customers be treated as a reduction in fuel costs that are paid by CINGSA’s customers. On January 4, 2016, CINGSA filed an appeal in Superior Court to Order U-15-016(14), stating the RCA violated CINGSA’s right to due process of law, erred, and/or acted unreasonably, unfairly, arbitrarily, capriciously, or contrary to applicable law. CINGSA believes additional proceeds resulting from the sale of found native gas should remain with CINGSA. Chugach filed an entry of appearance in the case on January 14, 2016. CINGSA filed its brief on June 6, 2016. Chugach filed its reply brief on October 31, 2016. Oral argument was held on March 6, 2017. On August 17, 2017, the Superior Court issued its order affirming the decisions by the RCA that it has authority in this case, that the RCA’s decision was not arbitrary, and that the RCA’s basis for assignment was reasonable. The RCA’s assignment allocation remains unchanged. There is no impact on Chugach’s margin levels as a result of a sale of found gas and any funds Chugach receives will be returned to members as a reduction to fuel expense. It is not known if or when CINGSA will sell any of the found gas. Operation and Regulation of the Alaska Railbelt Electric and Transmission System The 2014 Alaska Legislature directed the RCA to provide a recommendation on whether creating an independent system operator or similar structure in the Railbelt area is the best option for effective and efficient electrical transmission. On February 11, 2015, the RCA voted in favor of opening a docket to investigate and receive input on alternative transmission structures for the Railbelt. On June 30, 2015, the RCA issued its report which recommended an independent transmission company, certificated and regulated as a public utility, be created to operate the transmission system reliably and transparently and to plan and execute major maintenance, transmission system upgrades, and new transmission projects necessary for the reliable delivery of electric power to Railbelt customers. The RCA opened Docket I-15-001 to gather information on power pooling and/or centralized transmission system planning and operation among the Railbelt electric utilities, including economic dispatch of the Railbelt’s electrical generation units. Initial progress reports were filed with the RCA on September 30, 2015. With the support of the RCA, Chugach and several other Railbelt utilities are evaluating possible transmission business model opportunities and associated economic dispatch models that Chugach believes may lead to more optimal Railbelt-wide system operations. On February 1, 2016, Chugach and the Municipality of Anchorage d/b/a Municipal Light and Power (ML&P) filed a joint report regarding the development of a power pooling and joint dispatch arrangement between the utilities. The filing summarized several of the projected qualitative and quantitative benefits of such an arrangement. Chugach and ML&P filed subsequent joint reports regarding their progress toward joint dispatch and power pooling arrangements on May 2, 2016, and August 10, 2016. On October 31, 2016, Chugach, ML&P, and MEA filed a joint report informing the RCA that they were negotiating a power pooling and joint dispatch agreement. On January 27, 2017, Chugach, ML&P, and MEA entered into an Amended and Restated Power Pooling and Joint Dispatch Agreement (Agreement) which provides for economic dispatch resulting from coordinated scheduling of generation and transmission assets, including scheduling, dispatch, and settlement transactions at the bulk power level of electric services. The Agreement was submitted to the RCA as an informational filing on January 30, 2017 under Docket I-15-001. T he Agreement provides a contractual framework for coordinated scheduling, dispatch, and settlement transactions for the purchase, sale, or exchange of energy, capacity, reserves, and transmission ancillary services on an efficient and economic basis among the signatories to the Agreement. The Agreement provides for a one -year development period to develop and agree upon specific, detailed generation and transmission dispatch procedures, fuel supply dispatch procedures, and a settlement process. Upon finalization of dispatch procedures and the settlement process in 2018, Chugach, ML&P and MEA will submit the Agreement to the RCA for approval. |
Utility Plant
Utility Plant | 12 Months Ended |
Dec. 31, 2017 | |
Utility Plant [Abstract] | |
Utility Plant | (6) Utility Plant Major classes of utility plant as of December 31 are as follows: Electric plant in service: 2017 2016 Steam production plant $ 101,116,277 $ 101,116,277 Hydroelectric production plant 33,659,129 33,659,129 Other production plant 287,765,474 287,404,484 Transmission plant 296,018,078 282,040,969 Distribution plant 315,862,812 294,641,485 General plant 55,164,994 54,982,432 Unclassified electric plant in service 1 60,294,349 83,457,981 Intangible plant 1 5,455,371 5,455,371 Beluga River Natural Gas Field (BRU Asset & ARO) 47,927,331 47,927,331 Other 1 1,828,409 1,828,409 Total electric plant in service 1,205,092,224 1,192,513,869 Construction work in progress 17,952,573 18,455,940 Total electric plant in service and construction work in progress $ 1,223,044,797 $ 1,210,969,809 1 Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment. Intangible plant represents Chugach's share of a Bradley Lake transmission line financed internally. Other represents Electric Plant Held for Future Use. |
Investments In Associated Organ
Investments In Associated Organizations | 12 Months Ended |
Dec. 31, 2017 | |
Investments In Associated Organizations [Abstract] | |
Investments In Associated Organizations | (7) Investments in Associated Organizations Investments in associated organizations include the following at December 31: 2017 2016 NRUCFC Capital Term Certificates $ 6,095,980 $ 6,095,980 CoBank 2,819,307 3,188,490 Other 65,123 64,841 Total investments in associated organizations $ 8,980,410 $ 9,349,311 The Farm Credit Administration, CoBank's federal regulators, requires minimum capital adequacy standards for all Farm Credit System institutions. Loan agreements and financing arrangements with CoBank and NRUCFC require, as a condition of the extension of credit, that an equity ownership position be established by all borrowers. |
Deferred Charges And Liabilitie
Deferred Charges And Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Deferred Charges And Liabilities [Abstract] | |
Deferred Charges And Liabilities | (8) Deferred Charges and Liabilities Deferred Charges Deferred charges, net of amortization, consisted of the following at December 31: 2017 2016 Regulatory assets: Debt issuance and reacquisition costs $ 386,892 $ 492,850 Refurbishment of transmission equipment 95,679 104,939 Feasibility studies 237,425 1,387,285 Cooper Lake relicensing / projects 5,149,903 5,280,006 Fuel supply 1,801,970 2,005,052 Storm damage 453,166 647,381 Other regulatory deferred charges 815,722 849,933 Bond interest - market risk management 4,884,587 5,365,190 Environmental matters 978,820 1,024,171 Beluga parts and materials 10,696,210 0 Total regulatory assets 25,500,374 17,156,807 Other deferred charges: NRECA pension plan prepayment 7,204,591 7,925,050 Post retirement benefit obligation 59,100 59,100 Total other deferred charges 7,263,691 7,984,150 Total deferred charges $ 32,764,065 $ 25,140,957 Deferred charges, not currently being recovered in rates charged to consumers, consisted of the following at December 31: 2017 2016 Regulatory assets: Multi-stage Energy Storage $ 0 $ 1,117,860 Regulatory studies and other 201,775 46,721 Total regulatory assets 201,775 1,164,581 Other deferred charges: NRECA pension plan prepayment 0 7,925,050 Post retirement benefit obligation 59,100 59,100 Total other deferred charges 59,100 7,984,150 Total deferred charges $ 260,875 $ 9,148,731 We believe all regulatory assets not currently being recovered in rates charged to consumers are probable of recovery in the future based upon prior recovery of similar costs allowed by our regulator. The recovery of regulatory assets is approved by the RCA either in standard SRFs, general rate case filings or specified independent requests. In most cases, deferred charges are recovered over the life of the underlying asset. Deferred Liabilities Deferred liabilities, at December 31 consisted of the following: 2017 2016 Refundable consumer advances for construction $ 416,263 $ 328,360 Estimated initial installation costs for meters 100,927 118,854 Post retirement benefit obligation 732,200 732,200 Total deferred liabilities $ 1,249,390 $ 1,179,414 |
Patronage Capital
Patronage Capital | 12 Months Ended |
Dec. 31, 2017 | |
Patronage Capital [Abstract] | |
Patronage Capital | (9) Patronage Capital Chugach has a Board-approved capital credit retirement policy, which is contained in Chugach’s Financial Forecast. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members’ proportionate contribution to Chugach’s assignable margins. At De cember 31, 2017, Chugach had $172,928,887 of patronage capital (net of capital credits retired in 2017), which included $166,880,163 of patronage capital that had been assigned and $6,048,724 of patronage capital to be assigned to its members. At December 31, 2016 , Chugach had $169,996,436 of patronage capital (net of capital credits retired in 2016 ), which included $164,182,580 of patronage capital that had been assigned and $5,813,856 of patronage capital to be assigned to its members. Approval of actual capital credit retirements is at the discretion of the Chugach Board. Chugach records a liability when the retirements are approved by the Board. Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which was December 31, 2013 . This patronage capital retirement was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The RCA accepted the parties’ settlement agreement on August 9, 2007. We finalized a new agreement with HEA in September 2017 which spread their retirement payments between 2017 and 2020 in increments of $2.0 million annually. As a result, $2.0 million of HEA’s patronage capital was retired and paid in 2017, and $2.0 million of HEA’s patronage capital was reclassified to a current payable under other current liabilities leaving $ 3.9 million in long-term patronage capital payable at December 31, 2017. HEA’s patronage capital payable was $7.9 million at December 31, 201 6. In an agreement reached in May of 2014 with MEA, capital credits retired to MEA are classified as patronage capital payable on Chugach’s Balance Sheet . MEA’s patronage capital payable was $4. 9 million and $4. 1 million at December 31, 2017 and 2016 , respectively. T he Second Amended and Restated Indenture of Trust (Indenture) and the CoBank Second Amended and Restated Master Loan Agreement prohibit Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Indenture or debt agreements exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total long-term debt and equities and margins. Capital credit retirements authorized by our Board, less early retirements , were $2,631,928 , $3,001,426 , and $3,007,772 for the years ended December 31, 201 7 , 201 6 , and 201 5 , respectively. With the exception of MEA’s and HEA’s patronage capital payable, the outstanding liability for capital credits authorized but not paid at December 31, 2017 , 2016, and 2015 was $57,036 , $2,014,080, and $2,105,440 , respectively. |
Other Equities
Other Equities | 12 Months Ended |
Dec. 31, 2017 | |
Other Equities [Abstract] | |
Other Equities | (10) Other Equities A summary of other equities at December 31 follows: 2017 2016 Nonoperating margins, prior to 1967 $ 23,625 $ 23,625 Donated capital 2,213,876 2,001,450 Unclaimed capital credit retirement 1 12,415,752 11,803,000 Total other equities $ 14,653,253 $ 13,828,075 1 Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska’ s unclaimed property law and have therefore reverted to Chugach. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt [Abstract] | |
Debt | (11) Debt Long-term obligations at December 31 are as follows: 2017 2016 2011 Series A Bond of 4.20% , maturing in 2031 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012 63,000,000 67,500,000 2011 Series A Bond of 4.75% , maturing in 2041 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012 147,999,998 154,166,665 2012 Series A Bond of 4.01% , maturing in 2032 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013 56,250,000 60,000,000 2012 Series A Bond of 4.41% , maturing in 2042 , with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042 88,000,000 95,000,000 2012 Series A Bond of 4.78% , maturing in 2042 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023 50,000,000 50,000,000 2017 Series A Bond of 3.43% , maturing in 2037 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2018 40,000,000 0 2016 CoBank Note, 2.58% fixed rate note maturing in 2031 , with interest and principal due quarterly beginning in 2016 40,356,000 43,776,000 Total long-term obligations $ 485,605,998 $ 470,442,665 Less current installments 26,608,667 24,836,667 Less unamortized debt issuance costs 2,669,485 2,715,745 Long-term obligations, excluding current installments $ 456,327,846 $ 442,890,253 C ovenants Chugach is required to comply with all covenants set forth in the Indenture that secures the 2011 , 2012, and 2017 Series A Bonds, and the 201 6 CoBank Note . The CoBank Note is governed by the Second Amended and Restated Master Loan Agreement, which is secured by the Indenture dated January 20, 2011. Chugach is also required to comply with the 2016 Credit Agreement, between Chugach and NRUCFC, KeyBank National Association, Bank of America, N.A., and CoBank, ACB dated June 13 , 201 6 , governing loans and extensions of cr edit associated with Chugach’s commercial paper p rogram, in an aggregate principal amount not exceeding $150.0 million at any one time outstanding. Chugach is also required to comply with other covenants set forth in the Revolving Line of Credit Agreement with NRUCFC. Security The Indenture, which became effective on January 20, 2011, imposes a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt obligations. Assets that are generally not subject to the lien of the Indenture include cash (other than cash deposited with the indenture trustee); instruments and securities; patents, trademarks, licenses and other intellectual property; vehicles and other movable equipment; inventory and consumable materials and supplies; office furniture, equipment and supplies; computer equipment and software; office leases; other leasehold interests for an original term of less than five years; contracts (other than power sales agreements with members having an original term exceeding three years, certain contracts specifically identified in the indenture, and other contracts relating to the ownership, operation or maintenance of generation, transmission or distribution facilities); non-assignable permits, licenses and other contract rights; timber and minerals separated from land; electricity, gas, steam, water and other products generated, produced or purchased; other property in which a security interest cannot legally be perfected by the filing of a Uniform Commercial Code financing statement, and certain parcels of real property specifically excepted from the lien of the Indenture. The lien of the Indenture may be subject to various permitted encumbrances that include matters existing on the date of the Indenture or the date on which property is later acquired; reservations in United States patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business. Rates The Indenture also requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. If there occurs any material change in the circumstances contemplated at the time rates were most recently reviewed, the Indenture requires Chugach to seek appropriate adjustment to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges, provided, however, upon review of rates based on a material change in circumstances, rates are required to be revised in order to comply and there are less than six calendar months remaining in the current fiscal year, Chugach can revise its rates so as to reasonably expect to meet the covenant for the next succeeding 12-month period after the date of any such revision. The Second Amended and Restated Master Loan Agreement with CoBank, which became effective on June 30, 2016, also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense . Th e 2016 Credit Agreement governing the unsecured facility providing liquidity for Chugach’s Commercial Paper Program requires Chugach to maintain minimum margins for interest of at least 1.10 times interest charges for each fiscal year. Margins for interest generally consist of Chugach’s assignable margins plus total interest expense. Distributions to Members Under the Indenture and debt agreements, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Indenture or debt agreements exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total long-term debt and equities and margins. Maturities of Long ‑term Obligations Long-term obligations at December 31, 2017 , mature as follows: Year ending December 31 2011 Series A Bonds 2012 Series A Bonds 2016 CoBank Note 2017 Series A Bonds Total 2018 $ 10,666,667 $ 10,750,000 $ 3,192,000 $ 2,000,000 $ 26,608,667 2019 10,666,667 10,750,000 3,192,000 2,000,000 26,608,667 2020 10,666,667 10,750,000 3,420,000 2,000,000 26,836,667 2021 10,666,667 3,750,000 3,648,000 2,000,000 20,064,667 2022 10,666,667 3,750,000 3,876,000 2,000,000 20,292,667 Thereafter 157,666,663 154,500,000 23,028,000 30,000,000 365,194,663 $ 210,999,998 $ 194,250,000 $ 40,356,000 $ 40,000,000 $ 485,605,998 Lines of credit Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2017 or 2016, and therefore had no outstanding balance at December 31, 2017 and 2016. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was 3.00% at December 31, 2017, and 2.90% at December 31, 2016. The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12 -month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance. The NRUCFC line of credit was renewed effective September 29, 2017 , and expires September 29, 2022. This line of credit is immediately available for unconditional borrowing. Commercial Paper On June 13, 2016 , Chugach entered into a $150.0 million senior unsecured credit facility (Credit Agreement), which is used to back Chugach’s commercial paper program. The pricing includes an all-in drawn spread of one month LIBOR plus 90.0 basis points, along with a 10.0 basis points facility fee (based on an A/A2/A unsecured debt rating). The Credit Agreement will expire on June 13, 2021 . The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., and CoBank, ACB. Our commercial paper can be repriced between one day and 270 days. Chugach is expected to continue to issue commercial paper in 2018, as needed. Chugach had $50.0 million and $68.2 million of commercial paper outstanding at December 31, 2017 and 2016, respectively. The following table provides information regarding 201 7 monthly average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates: Month Average Balance Weighted Average Interest Rate Month Average Balance Weighted Average Interest Rate January $ 65.0 0.94 % July $ 41.1 1.40 % February $ 63.0 0.92 % August $ 41.5 1.40 % March $ 60.9 1.04 % September $ 45.7 1.40 % April $ 44.4 1.14 % October $ 48.4 1.39 % May $ 42.4 1.14 % November $ 46.0 1.39 % June $ 40.2 1.29 % December $ 48.7 1.67 % Financing On January 21, 2011 , Chugach issued $275.0 million of First Mortgage Bonds, 2011 Series A, in two tranches, Tranche A and Tranche B, for the purpose of refinancing the 2001 and 2002 Series A Bonds in 2011 and 2012, and for general corporate purposes. Interest is paid semi-annually on March 15 and September 15 commencing on September 15, 2011 . Principal on the 2011 Series A Bonds is paid in equal annual installments beginning March 15, 2012. On January 11, 2012 , Chugach issued $250.0 million of First Mortgage Bonds, 2012 Series A, in three tranches, Tranche A, Tranche B and Tranche C, for the purpose of repaying outstanding commercial paper used to finance SPP construction and for general corporate purposes. Interest is paid semi-annually March 15 and September 15 commencing on September 15, 2012 . The 2012 Series A Bonds, Tranche A and Tranche C, pay principal in equal installments on an annual basis beginning March 15, 2013, and 2023, respectively. The 2012 Series A Bonds, Tranche B, pay principal beginning March 15, 2013, through 2020, and on March 15, 2032, through 2042 . The bonds and all other long-term debt obligations are secured by a lien on substantially all of Chugach’s assets, pursuant to the Indenture, which became effective on January 20, 2011. On June 30, 2016, Chugach entered into a term loan facility with CoBank, evidenced by the 2016 CoBank Note, which is governed by the Second Amended and Restated Master Loan Agreement dated June 30, 2016, and secured by the Indenture. Chugach had $ 40.4 million and $ 43.8 million outstanding on this facility at December 31, 2017 , and 2016, respectively . On March 17, 2017, Chugach issued $40,000,000 of First Mortgage Bonds, 2017 Series A, due March 15, 2037 for general corporate purposes. The 2017 Series A Bonds will mature on March 15, 2037, and will bear interest at 3.43% . Interest will be paid each March 15 and September 15, commencing on September 15, 2017. The 2017 Series A Bonds will pay principal in equal installments on an annual basis beginning March 15, 2018 . The bonds are secured, ranking equally with all other long-term obligations, by a first lien on substantially all of Chugach’s assets, pursuant to the Sixth Supplemental Indenture to the Second Amended and Restated Indenture of Trust, which initially became effective on January 20, 2011, as previously amended and supplemented. The following table provides additional information regarding the 2011 Series A , 2012 Series A , and 2017 Series A bonds and the 2016 CoBank Note at December 31, 2017 (dollars in thousands): Maturing March 15, Average Life (Years) Interest Rate Issue Amount Carrying Value 2011 Series A, Tranche A 2031 6.7 4.20 % $ 90,000 $ 63,000 2011 Series A, Tranche B 2041 11.7 4.75 % 185,000 148,000 2012 Series A, Tranche A 2032 7.2 4.01 % 75,000 56,250 2012 Series A, Tranche B 2042 15.0 4.41 % 125,000 88,000 2012 Series A, Tranche C 2042 14.7 4.78 % 50,000 50,000 2017 Series A, Tranche A 2037 10.2 3.43 % 40,000 40,000 2016 CoBank Note 2031 5.7 2.58 % 45,600 40,356 Total $ 610,600 $ 485,606 |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2017 | |
Employee Benefit Plans [Abstract] | |
Employee Benefit Plans | ( 12) Employee Benefit Plans Pension Plans Pension benefits for substantially all union employees are provided through the Alaska Electrical Pension Trust Fund and the UNITE HERE National Retirement Fund, multi-employer plans. Chugach pays an hourly amount per eligible union employee pursuant to the collective bargaining unit agreements. In these master, multi-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer. Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Plan (RS Plan). The RS Plan is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue Code. Under ASC 960, “Topic 960 – Plan Accounting – Defined Benefit Pension Plans,” the RS Plan is a multi-employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. Chugach makes annual contributions to the RS Plan equal to the amounts accrued for pension expense. Chugach made contributions to all significant pension plans for the years ended December 31, 2017, 2016 and 2015 of $5.9 million, $6.7 million and $6.7 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2017, 2016 and 2015. In December 2012, a committee of the NRECA Board of Directors approved an option to allow participating cooperatives in the Retirement Security (RS) Plan (a defined benefit multi - employer pension plan) to make a prepayment and reduce future required contributions. The prepayment amount is a cooperative’s share, as of January 1, 2013, of future contributions required to fund the RS Plan’s unfunded value of benefits earned to date using Plan actuarial valuation assumptions. The prepayment amount will typically equal approximately 2.5 times a cooperative’s annual RS Plan required contribution as of January 1, 2013. After making the prepayment, for most cooperatives the billing rate is reduced by approximately 25% , retroactive to January 1 of the year in which the amount is paid to the RS Plan . The 25% differential in billing rates is expected to continue for approximately 15 years from January 1, 2013 . However unexpected changes in interest rates, asset returns and other plan experience , plan assumption changes, and other factors may have an impact on the differential in billing rates and the 15 - year period. On December 29, 2 0 16, Chugach made a prepayment of $7.9 million to the NRECA RS Plan. See Note 2 o – “Deferred Charges and Liabilities.” The following table provides information regarding pension plans which Chugach considers individually significant: Alaska Electrical Pension Plan 3 NRECA Retirement Security Plan 3 Employer Identification Number 92-6005171 53-0116145 Plan Number 001 333 Year-end Date December 31 December 31 Expiration Date of CBA's June 30, 2021 N/A 2 Subject to Funding Improvement Plan No No 4 Surcharge Paid N/A N/A 4 2017 2016 2015 2017 2016 2015 Zone Status Green Green Green N/A 1 N/A 1 N/A 1 Required minimum contributions None None None N/A N/A N/A Contributions (in millions) $3.3 $3.2 $3.1 $2.6 $3.5 $3.5 Contributions > 5% of total plan contributions Yes Yes Yes No No No 1 A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. 2 The CEO is the only participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through April 30 , 20 20 . 3 The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are available on Chugach’s website at www.chugachelectric.com . 4 The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the RS Plan and may change as a result of plan experience. Health and Welfare Plans Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund. Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach. Chugach pays a defined amount per union employee pursuant to collective bargaining unit agreements. Amounts charged to benefit costs and contributed to the health and welfare plans for these benefits for th e years ending December 31, 2017 , 201 6, and 2015 were $4.8 million, $4.5 million, and $4.5 million, respectively. Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees. Amounts charged to benefit cost and contributed to this plan for those benefits for t he years ended December 31, 2017 , 201 6 , and 201 5 totaled $2.8 million, $2.8 million, and $2.6 million , respectively. Money Purchase Pension Plan Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement. Contributions to the Plan are made based on a percentage of each employee’s compensation. Contributions to the money purchase pension plan for the years ending December 31, 201 7 , 201 6 and 201 5 were $141.8 thousand, $132.3 thousand and $133.6 thousand, respectively. 401(k) Plan Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately. Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $18,000 in 2017, 2016 , and 2015 , and allowed catch-up contributions for those over 50 years of age of $6,000 in 2017, 2016, and 2015 . Chugach does not make contributions to the plan. Deferred Compensation Effective January 1, 2011, Chugach participates in Vanguard’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received. The program is a non-qualified plan under Internal Revenue Code 457(b). Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made. The amounts credited to the deferred compensation account, including gains or losses, are retained by Chugach until the entire amount credited to the account has been distributed to the participant or to the participant’s beneficiary. The balance of the Program for the years ending December 31, 201 7 , and 201 6 was $1,229,294 and $907,836 , respectively. Potential Termination Payments Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows: two weeks for each year of service to a maximum of 26 weeks for 13 years or more of service. |
Bradley Lake Hydroelectric Proj
Bradley Lake Hydroelectric Project | 12 Months Ended |
Dec. 31, 2017 | |
Bradley Lake Hydroelectric Project [Abstract] | |
Bradley Lake Hydroelectric Project | (13) Bradley Lake Hydroelectric Project Chugach is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake). Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166.0 million of revenue bonds. Chugach and other participating utilities have entered into take ‑or ‑pay power sales agreements under which shares of the project capacity have been purchased and the participants have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt service costs and amounts required to maintain established reserves). Under these take ‑or ‑pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced. Chugach has a 30.4% share, or 27.4 megawatts (MW) as currently operated, of the project’s capacity. The share of Bradley Lake indebtedness for which we are responsible is approximately $16.3 million. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant’s percentage share is increased by more than 25% . Upon default, Chugach could be faced with annual expenditures of approximately $6.0 million as a result of Chugach’s Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel recovery process. The Battle Creek Diversion Project (Project) is a project to increase water available for generation by constructing a diversion on the West Fork of Upper Battle Creek to divert flows to Bradley Lake, increasing annual energy output by an estimated 37,000 MWh. The Bradley Lake Project Management Committee (BPMC) approved the project October 13, 2017, as amended December 1, 2017, and December 6, 2017. The Project cost is estimated at $47.0 million and the BMPC approved financing in this amount on December 6, 2017. The project is estimated to begin in the Spring of 2018 with an estimated completion date of 2020. Not all Bradley Lake purchasers are participating in the development and resulting benefits of the Project at this time, although they have preserved their ability to participate in the Project at a later date. Chugach would be entitled to 39.38% of the additional energy produced if no additional participants elect to join . The following represents information with respect to Bradley Lake at June 30, 2017 (the most recent date for which information is available). Chugach's share of expenses was $6,452,898 in 2017, $5,662,522 in 2016, and $5,663,304 in 2015 and is included in purchased power in the accompanying financial statements. (In thousands) Total Proportionate Share Plant in service $ 162,907 $ 49,524 Long-term debt 43,940 13,358 Interest expense 2,652 806 Chugach's share of a Bradley Lake transmission line financed internally is included in Intangible Electric Plant . |
Eklutna Hydroelectric Project
Eklutna Hydroelectric Project | 12 Months Ended |
Dec. 31, 2017 | |
Eklutna Hydroelectric Project [Abstract] | |
Eklutna Hydroelectric Project | (14) Eklutna Hydroelectric Project Along with two other utilities, Chugach purchased the Eklutna Hydroelectric Project from the Federal Government in 1997. Ownership was transferred from the United States Department of Energy’s Alaska Power Administration jointly to Chugach ( 30% ), MEA ( 17% ) and ML&P ( 53% ). Plant in service in 201 7 included $3,967,933 , net of accumulated depreciation of $2,591,717 , which represents Chugach’s share of the Eklutn a Hydroelectric Project. In 2016 , plant in service included $4,229,167 , net of accumulated depreciation of $2,442,175 . The facility is operated by Chugach and maintained jointly by Chugach and ML&P. Each participant contributes their proportionate share for operation, maintenance and capital improvement costs to the plant, as well as to the transmission line between Anchorage and the plant. When MEA was an all-requirements wholesale customer, u nder net bil ling arrangements, Chugach reimbursed MEA for their share of the costs. Chugach’s share of expenses was $403,511 , $532,678 , and $689,501 in 2017, 2016, and 2015 , respectively, and is included in purchased power, power production and depreciation expense in the accompanying financial statements. ML&P performs major maintenance at the plant. Chugach performs the daily operation and maintenance of the power plant, providing personnel who perform daily plant inspections, meter reading, monthly report preparation, and other activities as required. |
Beluga River Unit
Beluga River Unit | 12 Months Ended |
Dec. 31, 2017 | |
Beluga River Unit [Abstract] | |
Beluga River Unit | (15) Beluga River Unit On February 4, 2016 , Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. (CPAI) and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” The Purchase and Sale Agreement transfers CPAI’s working interest in the BRU to Chugach and ML&P. The total purchase price was $148.0 million, with Chugach’s portion totaling $44.4 million. Chugach’s interest in the BRU is to reduce the cost of electric service to its retail and wholesale members by securing an additional long-term supply of natural gas to meet on-going generation requirements. The acquisition complements existing gas supplies and is expected to provide greater fuel diversity. Under the joint bid arrangement, Chugach’s ownership of CPAI’s working interest is 30% and ML&P’s ownership is 70% . The ownership shares include the attendant rights and privileges of all gas and oil resources, including 15,500 lease acres ( 8,200 in Unit / Participating Area and 7,300 held by Unit), Sterling and Beluga producing zones, and CPAI’s 67% working interest in deep oil resources. On April 21, 2016, the acquisition was approved by the RCA and the transaction closed on April 22, 2016. Additionally , CPAI had contractual gas sales obligations to ENSTAR through 2017 . Th is contract w as assumed by ML&P and Chugach on the basis of ownership share. The BRU is located on the western side of Cook Inlet, approximately 35 miles from Anchorage, and is an established natural gas field that was originally discovered in 1962. The BRU was jointly owned ( one -third) by CPAI, Hilcorp, and ML&P. Following the acquisition, ML&P’s ownership of the BRU increased to approximately 56.7% , Hilcorp’s ownership remained unchanged at 33.3% , and Chugach’s ownership is 10.0% . T he BRU acquisition costs were recorded as deferred charges on Chugach’s balance sheet and totaled $1.5 million at December 31, 2016. Chugach requested that these costs be amortized based on units of production of the BRU and recognized as depreciation and amortization on Chugach’s statement of operations. Chugach also requested approval to recover the deferred costs in the gas transfer price. The RCA issued an order combining the BRU cost recovery process and the request to create a regulatory asset into a single docket. On October 26, 2017, the RCA issued a final order accepting Chugach’s filing and closing the docket, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga River Unit Gas Transfer Price.” Each of the BRU participants has a right to take their interest of the gas produced. Parties that take less than their interest of the field’s output may either accept a cash settlement for their underlift or take their underlifted gas in future years. As part of the BRU acquisition, Chugach acquired 30% of CPAI’s underlift, which was 69,099 Mcf at acquisition and was in an overlift position of 8 Mcf and 84 Mcf at December 31, 2017 and 2016, respectively. Chugach has opted to take any cumulative underlift in gas in the future and will record the gas as fuel expense on the statement of operations when received. The revenue generated by Chugach’s interest in the BRU operations is primarily associated with the gas sold to ENSTAR, pursuant to the aforementioned contract, which expire d December 31, 2017. Chugach recognized revenue from the BRU in the amount of $6.6 million and $2.8 million through December 31, 2017 and 2016, respectively. Chugach records depreciation, depletion and amortization on BRU assets based on units of production. During 2017, Chugach lifted 1.4 Bcf resulting in a cumulative lift s ince purchase of 3.1 Bcf of the approximate 25.1 Bcf in Chugach’s proven developed reserves. Chugach, and other owners, ML&P and Hilcorp, are operating under an existing Joint Operating Agreement. Hilcorp is the operator for BRU. The owners are considering updating the existing Joint Operating Agreement to better match the new owners’ interests. In addition to the operator fees to Hilcorp, other BRU expenses include royalty expense and interest on long-term debt. All expenses other than depreciation, depletion and amortization and interest on long-term debt are included as fuel expense on Chugach’s statement of operations. Chugach has applied and qualified for a small producer tax credit, provided by the State of Alaska, resulting in an estimate of no liability for production taxes. The revenue in excess of expenses less the allowed TIER from BRU operations is adjusted through Chugach’s fuel and purchased power adjustment process. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies [Abstract] | |
Commitments And Contingencies | (16 ) Commitments and Contingencies Contingencies Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity. Chugach establishes reserves when a particular contingency is probable and calculable. Chugach has not accrued for any contingency at December 31, 2017 , as it does not consider any contingency to be probable nor calculable. Chugach faces contingencies that are reasonably possible to occur; however, they cannot currently be estimated. Concentrations Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have a CBA with the Hotel E mployees and Restaurant Employees (HERE). All three IBEW CBA’s and the HERE CBA have been renewed through June 30, 2021 . Fuel Supply Contracts Chugach entered into a gas contract with Hilcorp effective January 1, 2015 , to provide gas through March 31, 2018 . On September 15, 2014 , the RCA approved an amendment to the Hilcorp gas purchase agreement extending gas delivery and subsequently filling 100 percent of Chugach’s needs through March 31, 2019 . On September 8, 2015 , the RCA approved another amendment to the Hilcorp gas purchase agreement extending the term of the agreement, thus filling up to 100 percent of Chugach’s needs through March 31, 2023 . The total amount of gas under this contract is estimated to be 60 Bcf. All of the production is expected to come from Cook Inlet, Alaska. The terms of the Hilcorp agreement require Chugach to manage the natural gas transportation over the connecting pipeline systems. Chugach has gas transportation agreements with ENSTAR Natural Gas Company (ENSTAR) and Hilcorp. The RCA approved a natural gas supply contract with Marathon Alaska Production, LLC (MAP) effective May 17, 2010. This contract includes two contract extensions that were exercised in 2011. Effective February 1, 2013, this gas purchase agreement was assigned to Hilcorp, who purchased MAP’s assets in Cook Inlet. This contract began providing gas April 1, 2011 , and will expire March 31, 2023 . The total amount of gas under contract is currently estimated up to 49 Bcf. These contracts fill 100% of Chugach’s needs through March 31, 2023. All of the production is expected to come from Cook Inlet, Alaska. In 2017, 81% of our power was generated from gas, with 14% generated at the Beluga Power Plant and 81% generated at SPP. In 2016, 77% of our power was generated from gas, with 9% generated at Beluga and 88% generated at SPP. The following represents the cost of fuel purchased and or transported from various vendors as a percentage of total fuel costs for the years ended December 31: 2017 2016 2015 Hilcorp 88.4 % 56.9 % 30.3 % Furie 5.3 % 0.0 % 0.0 % ConocoPhillips (COP) 0.0 % 32.0 % 58.7 % AIX Energy 0.1 % 0.7 % 4.7 % ENSTAR 3.4 % 4.7 % 3.3 % Harvest (Hilcorp) Pipeline 2.1 % 3.2 % 1.6 % Miscellaneous 0.7 % 2.5 % 1.4 % Patronage Capital Payable Pursuant to agreements reached with HEA and MEA, and discussed in Note (9) – “Patronage Capital,” patronage capital allocated or retired to HEA or MEA is classified as patronage capital payable on Chugach’s balance sheet. The Board of Directors approved a capital credit retirement on September 27, 2017. MEA received a retirement of $0.8 million, increasing their payable to $4.9 million at December 31, 2017. We also finalized a new agreement with HEA in September 2017, which spread their retirement payments between 2017 and 2020 in increments of $2.0 million annually. As a result, $2.0 million of HEA’s patronage capital was retired and paid in 2017, and $2.0 million of HEA’s patronage capital was reclassified to a current payable under other current liabilities leaving $3.9 million in long term patronage capital payable at December 31, 2017. At December 31, 2016, patronage capital payable to HEA and MEA was $7.9 million and $4.1 million, respectively. Regulatory Cost Charge In 1992, the State of Alaska Legislature passed legislation authorizing the Department of Revenue to collect a Regulatory Cost Charge from utilities to fund the governing regulatory commission, which is currently the RCA. The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption. The tax is collected monthly and remitted to the State of Alaska quarterly. The Regulatory Cost Charge has changed since its inception (November of 1992) from an initial rate of $0.000626 per kWh to the current rate of $0.000899 , effective July 1, 2017 . The tax is reported on a net basis and the tax is not included in revenue or expense. Sales Tax Chugach collects sales tax on retail electricity sold to Kenai and Whittier consumers. The tax is collected monthly and remitted to the Kenai Peninsula Borough quarterly. Sales tax is reported on a net basis and the tax is not included in revenue or expense. Gross Revenue Tax Chugach pays to the State of Alaska a gross re venue tax in lieu of state and local ad valorem, income and excise taxes on electricity sold in the retail market. The tax is collected monthly and remitted annually . Underground Compliance Charge In 2005, the Anchorage Municipal Assembly adopted an ordinance to require utilities to convert overhead distribution lines to underground. To comply with the ordinance, Chugach must expend two percent of a three -year average of gross retail revenue within the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with Alaska Statutes regarding undergrounding programs, Chugach is permitted to amend its rates by adding a two percent charge to its retail members’ bills to recover the actual costs of the program. The rate amendments are not subject to RCA review or approval. Chugach’s liability was $4,206,223 and $2,507,482 for this charge at December 31, 2017 and 2016 , respectively, and is included in other current liabilities. These funds are used to offset the costs of the undergrounding program. Environmental Matters Since January 1, 2007, transformer manufacturers have been required to meet the US Department of Energy (DOE) efficiency levels as defined by the Energy Act of 2005 (Energy Act) for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels increased from the original “TP1” levels to the new “DOE-2016” levels. All new transformers are DOE-2016 compliant. At this time a small increase in capital costs is anticipated along with a reduction in energy losses. The Clean Air Act and Environmental Protection Agency (EPA) regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants. New Clean Air Act regulations impacting electric utilities may result from future events or new regulatory programs. On August 3, 2015, the EPA released the final 111(d) regulation language aimed at reducing emissions of carbon dioxide (CO 2 ) from existing power plants that provide electricity for utility customers. In the final rule, the EPA took the approach of making individual states responsible for the development and implementation of plans to reduce the rate of CO 2 emissions from the power sector. The EPA initially applied the final rule to 47 of the contiguous states. At this time, Alaska, Hawaii, Vermont, Washington D.C. and two U.S. territories are not bound by the regulation. Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the DC Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the US Court of Appeals for the District of Columbia Circuit heard oral arguments challenging the legality of the Clean Power Plan. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the Clean Power Plan. The EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s financial condition, results of operations, or cash flows. While Chugach cannot predict the implementation of any additional new law or regulation, or the limitations thereof, it is possible that new laws or regulations could increase capital and operating costs. Chugach has obtained or applied for all Clean Air Act permits currently required for the operation of generating facilities. Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. Chugach does not believe that compliance with these statutes and regulations to date has had a material impact on its financial condition, results of operation or cash flows. However, the implementation of any additional new law or regulation, or the limitations thereof, or changes in or new interpretations of laws or regulations could result in significant additional capital or operating expenses. Chugach monitors proposed new regulations and existing regulation changes through industry associations and professional organizations. |
Quarterly Results Of Operations
Quarterly Results Of Operations | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Results Of Operations [Abstract] | |
Quarterly Results Of Operations | (1 7 ) Quarterly Results of Operations (unaudited) 201 7 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 62,934,930 $ 49,405,607 $ 51,554,650 $ 60,793,482 Operating Expense 52,778,100 44,850,594 48,365,752 51,223,238 Net Interest 5,575,665 5,569,961 5,535,031 5,520,479 Net Operating Margins 4,581,165 (1,014,948) (2,346,133) 4,049,765 Nonoperating Margins 157,569 207,513 201,916 211,877 Assignable Margins $ 4,738,734 $ (807,435) $ (2,144,217) $ 4,261,642 201 6 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 57,741,954 $ 45,132,973 $ 44,622,517 $ 50,250,135 Operating Expense 47,000,307 40,308,301 41,472,710 42,359,071 Net Interest 5,341,242 5,427,440 5,247,404 5,385,211 Net Operating Margins 5,400,405 (602,768) (2,097,597) 2,505,853 Nonoperating Margins 231,683 125,332 127,871 123,077 Assignable Margins $ 5,632,088 $ (477,436) $ (1,969,726) $ 2,628,930 |
Significant Accounting Polici24
Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2017 | |
Significant Accounting Policies [Abstract] | |
Management Estimates | a. Management Estimates In preparing the financial statements in conformity with United States generally accepted accounting principles (GAAP), the management of Chugach is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Estimates include the allowance for doubtful accounts, workers’ compensation liability, deferred charges and liabilities, unbilled revenue, estimated useful life of utility plant, cost of removal and asset retirement obligation (ARO), and remaining proved BRU reserves. Actual results could differ from those estimates. |
Regulation | b. Regulation The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.” FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. Our regulated rates are established to recover all of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings and our rates, see Note (2o ) – “ Defer red Charges and Liabilities .” |
Utility Plant And Depreciation | c. Utility Plant and Depreciation Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, removal cost, less salvage, is charged to accumulated depreciation . Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred. In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain asset groups are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset group may not be recoverable in rates. Recoverability of asset groups to be held and used is measured by a comparison of the carrying amount of an asset group to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset group exceeds the fair value of the asset. Depreciation and amortization rates have been applied on a straight ‑line basis and at December 31, 2017 are as follows: Annual Depreciation Rate Ranges Six months ending June 30, 2017 Six months ending December 31, 2017 Steam production plant 3.15% - 3.84% 3.03% - 3.26% Hydroelectric production plant 1.06% - 3.00% 0.88% - 2.71% Other production plant 3.15% - 8.85% 2.18% - 3.46% Transmission plant 1.58% - 7.86% 1.01% - 10.50% Distribution plant 2.16% - 9.63% 1.40% - 10.00% General plant 1.57% - 20.00% 1.95% - 33.33% Other 2.75% - 2.75% 2.75% - 2.75% On March 23, 2017, the RCA approved revised depre ciation rates effective July 1, 2017 in Docket U-16-081(2) . Chugach’s depreciation rates include a provision for cost of removal. Chugach records a separate liability for the estimated obligation related to the cost of removal. Chugach records Depreciation, Depletion and Amortization (DD&A) expense on the BRU assets based on units of production using the following formula: ten percent of the total production from the BRU as provided by the operator divided by ten percent of the estimated remaining proved reserves (in thousand cubic feet (Mcf)) in the field multiplied by Chugach’s total assets in the BRU. |
Full Cost Method | d. Full Cost Method Pursuant to FASB ASC 932-360-25, “Extractive Activities-Oil and Gas – Property, Pla nt and Equipment – Recognition,” Chugach has elected the Full C ost method, rather than the Successful Efforts method, to account for exploration and development costs of gas reserves. |
Asset Retirement Obligation (ARO) | e. Asset Retirement Obligation (ARO) Chugach calculated and recorded an Asset Retirement Obligation associated with the BRU. Chugach uses its BRU financing rate as its credit adjusted risk free rate and the expected cash flow approach to calculate the fair value of the ARO liability. The ARO asset is depreciated using the DD&A formula previously discussed. The ARO liability is accreted using the interest method of allocation. |
Investments In Associated Organizations | f. Investments in Associated Organizations The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is less than one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 201 7 , 201 6 or 201 5 . |
Investments - Other | g. Investments – Other Inv estments – other cons ists of certificates of deposit with a maturity greater than 12 months. Total investments – other were $3.1 million as of December 31, 2016 . |
Special Funds | h. Special Funds Special funds includes deposits associated with the deferred compensation plan and an investment associated with the BRU ARO. The BRU ARO investment was established pursuant to an agreement with the State of Alaska and was $0.2 million as of December 31, 2017. |
Cash And Cash Equivalents / Restricted Cash Equivalents | i . Cash and Cash Equivalents / Restricted Cash Equivalents For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has a concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. The concentration account had an average balance of $6,454,809 and $5,897,767 during the years ended December 31, 201 7 and 201 6 , respectively. Restricted cash equivalents include funds on deposit for future workers’ compensation claims . Total current and long term restricted cash equivalents were $1.7 million at December 31, 201 7 and 201 6 . |
Marketable Securities | j . Marketable Securities Chugach’s marketable securities consist of bond mutual funds , corporate bonds, and certificates of deposit with a maturity less than 12 months, classified as trading securities, reported at fair value with gains and losses in earnings. Net gains on marketable securities are included in nonoperating margins – capital credits, patronage dividends and othe r, and are summarized as follows: Twelve months ended December 31, 2017 Net gains and losses recognized during the period on trading securities $ 59,182 Less: Net gains and losses recognized during the period on trading securities sold during the period 0 Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date $ 59,182 |
Accounts Receivable | k . Accounts Receivable Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receiv able are invoiced amounts to ML&P for their proportionate share of current Southcentral Power Project ( SPP ) costs, which amounted to $1.3 million and $1.4 million in 201 7 and 201 6 , respectively. At December 31, 2017 and 2016 , accounts receivable also included $ 1.1 million and $0.7 million, respectively, from BRU operations primarily associated with gas sales to ENSTAR. |
Materials And Supplies | l . Materials and Supplies Materials and supplies are stated at average cost. |
Fuel Stock | m . Fuel Stock Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natu ral Gas Storage Alaska (CINGSA) . Chugach’s fuel balance in storage for the years ended December 31, 201 7 and 201 6 amounted to $ 6 . 9 million and $6.3 million, respectively. |
Fuel And Purchased Power Cost Recovery | n . Fuel and Purchased Power Cost Recovery Expenses associated with electric services include fuel purchased from others and produced from Chugach’s interest in the BRU, both of which are used to generate electricity, as well as power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel and purchased power adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under- or over-collection of fuel and purchased power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. |
Deferred Charges and Liabilities | o . Deferred Charges and Liabilities Included in deferred charges and liabilities on Chugach’s financial statements are regulatory assets and liabilities recorded in accordance with FASB ASC 980 . See Note 8 – Deferred Charges and Liabilities . Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. Chugach’s regulatory asset recoveries are embedded in base rates approved by the RCA. Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard Simplified Rate Filings (SRF), general rate case filings or specified independent requests. The rates approved related to the regulatory assets are matched to the amortization of actual expenses recognized. The regulatory assets are amortized and collected through rates over differing periods depending upon the period of benefit as established by the RCA. Deferred liabilities include refundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construct ion are held in deferred liabilities pending their return or other disposition. If events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on Chugach’s financial position, results of operations or cash flows. On December 29, 2016, Chugach made a prepayment of $7.9 million to the National Rural Electric Cooperative Association (NRECA) Retirement and Security (RS) Plan, which is included in deferred charges. Chugach recorded the long term prepayment in deferred charges and is amortizing the deferred charge to administrative, general and other expense, over 11 years, which represents the difference between the normal retirement age of 62 and the average age of Chuga ch’s employees in the RS Plan. The balance of the prepayment in deferred charges at December 31, 2017 and 2016 was $ 7.2 million and $7.9 million, respectively . |
Patronage Capital | p . Patronage Capital Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach’s statement of operations as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors (Board). Retained assignable margins are designated on Chugach’s balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board may also approve the return of capital to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September of 2002. |
Consumer Deposits | q . Consumer Deposits Consumer deposits include amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 201 7 and 201 6 , totaled $3.7 million and $3.3 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.6 million and $1.9 million for the years ended December 31, 2017 and 2016. |
Fair Value Of Financial Instruments | r . Fair Value of Financial Instruments FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments: Cash and cash equivalents – the carrying amount approximates fair value because of the short maturity of those instruments. Restricted cash – the carrying amount approximates fair value because of the short maturity of those instruments. Marketable securities – the carrying amount approximates fair value as changes in the market value are recorded monthly and gains or losses are reported in earnings (see note 2 j and note 4). Long ‑term obligations – the fair value estimate is based on the quoted market price for same or similar issues (see note 11). Consumer deposits – the carrying amount approximates fair value because of the short refunding term. The fair value of accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature. |
Operating Revenues | s . Operating Revenues Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,674,543 and $10,940,274 of unbilled retail reven ue at December 31, 2017 and 2016 , respectively , which is included in accounts receivable on the balance sheet . Wholesale revenue is recorded from metered locations on a calendar month basis, so no estimation is required. Chugach's tariffs include provisions for the recovery of gas costs according to gas supply contracts, as well as purchased power costs. |
Capitalized Interest | t . Capitalized Interest Allowance for funds used during construction (AFUDC) and interest charged to construction ‑ credit (IDC) are the estimated costs of the funds used during the period of construction from both equity and borrowed funds. AFUDC and IDC are applied to specific projects during construction. AFUDC and IDC calculations use the net cost of borrowed funds when used and is recovered through RCA approved rates as utility plant is depreciated. For all projects Chugach capitalized such funds at the weighted average rate of 4.1% during 201 7 and 4.3 % during 201 6 and 201 5 . |
Environmental Remediation Costs | u . Environmental Remediation Costs Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset. |
Income Taxes | v . Income Taxes Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 201 7 , 201 6 and 201 5 was in compliance with that provision. In addition, as described in Note (16 ) – “Commitments and Contingencies,” Chugach collects sales tax and is assessed gross revenue and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.” Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties. FASB ASC 740, “Topic 740 – Income Taxes,” only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding or retroactive tax positions that were not highly certain of being sustained upon examination by the taxing authorities. Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 201 5 through December 31, 201 7 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 201 7 . |
Grants | w . Grants Chugach has received federal and state grants to offset storm related expenditures and to support investigating means of mitigating the impact of renewable generation variability on the grid as well as the construction of facilities to transport fuel, divert water and safely transmit electricity to its consumers. Grant proceeds used to construct or acquire equipment are offset against the carrying amount of the related assets while grant proceeds for storm related expenditures are offset again st the actual expense incurred. Chugach received no grants in 2017 and $0.6 million in 2016. |
Significant Accounting Polici25
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Significant Accounting Policies [Abstract] | |
Schedule Of Depreciation And Amortization Rates | Six months ending June 30, 2017 Six months ending December 31, 2017 Steam production plant 3.15% - 3.84% 3.03% - 3.26% Hydroelectric production plant 1.06% - 3.00% 0.88% - 2.71% Other production plant 3.15% - 8.85% 2.18% - 3.46% Transmission plant 1.58% - 7.86% 1.01% - 10.50% Distribution plant 2.16% - 9.63% 1.40% - 10.00% General plant 1.57% - 20.00% 1.95% - 33.33% Other 2.75% - 2.75% 2.75% - 2.75% |
Schedule Of Gains And Losses On Trading Securities | Twelve months ended December 31, 2017 Net gains and losses recognized during the period on trading securities $ 59,182 Less: Net gains and losses recognized during the period on trading securities sold during the period 0 Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date $ 59,182 |
Fair Value Of Assets And Liab26
Fair Value Of Assets And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Of Assets And Liabilities [Abstract] | |
Schedule Of Marketable Securities | December 31, 2017 Total Level 1 Level 2 Level 3 Bond mutual funds $ 8,109,242 $ 8,109,242 $ 0 $ 0 Corporate bonds $ 248,335 $ 248,335 $ 0 $ 0 Certificates of deposit $ 3,063,323 $ 3,063,323 $ 0 $ 0 December 31, 2016 Total Level 1 Level 2 Level 3 Bond mutual funds $ 7,375,381 $ 7,375,381 $ 0 $ 0 Certificates of deposit $ 3,061,434 $ 3,061,434 $ 0 $ 0 |
Schedule Of Estimated Fair Value Of Long-Term Obligations Included In Financial Statements | Carrying Value Fair Value Level 2 Long-term obligations (including current installments) $ 485,606 $ 511,196 |
Utility Plant (Tables)
Utility Plant (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Utility Plant [Abstract] | |
Schedule Of Major Classes Of Utility Plant | Electric plant in service: 2017 2016 Steam production plant $ 101,116,277 $ 101,116,277 Hydroelectric production plant 33,659,129 33,659,129 Other production plant 287,765,474 287,404,484 Transmission plant 296,018,078 282,040,969 Distribution plant 315,862,812 294,641,485 General plant 55,164,994 54,982,432 Unclassified electric plant in service 1 60,294,349 83,457,981 Intangible plant 1 5,455,371 5,455,371 Beluga River Natural Gas Field (BRU Asset & ARO) 47,927,331 47,927,331 Other 1 1,828,409 1,828,409 Total electric plant in service 1,205,092,224 1,192,513,869 Construction work in progress 17,952,573 18,455,940 Total electric plant in service and construction work in progress $ 1,223,044,797 $ 1,210,969,809 1 Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment. Intangible plant represents Chugach's share of a Bradley Lake transmission line financed internally. Other represents Electric Plant Held for Future Use. |
Investments In Associated Org28
Investments In Associated Organizations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Investments In Associated Organizations [Abstract] | |
Schedule Of Investments In Associated Organizations | 2017 2016 NRUCFC Capital Term Certificates $ 6,095,980 $ 6,095,980 CoBank 2,819,307 3,188,490 Other 65,123 64,841 Total investments in associated organizations $ 8,980,410 $ 9,349,311 |
Deferred Charges And Liabilit29
Deferred Charges And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets [Line Items] | |
Schedule Of Deferred Charges, Or Regulatory Assets | 2017 2016 Regulatory assets: Debt issuance and reacquisition costs $ 386,892 $ 492,850 Refurbishment of transmission equipment 95,679 104,939 Feasibility studies 237,425 1,387,285 Cooper Lake relicensing / projects 5,149,903 5,280,006 Fuel supply 1,801,970 2,005,052 Storm damage 453,166 647,381 Other regulatory deferred charges 815,722 849,933 Bond interest - market risk management 4,884,587 5,365,190 Environmental matters 978,820 1,024,171 Beluga parts and materials 10,696,210 0 Total regulatory assets 25,500,374 17,156,807 Other deferred charges: NRECA pension plan prepayment 7,204,591 7,925,050 Post retirement benefit obligation 59,100 59,100 Total other deferred charges 7,263,691 7,984,150 Total deferred charges $ 32,764,065 $ 25,140,957 |
Schedule Of Deferred Credits, Or Regulatory Liabilities | 2017 2016 Refundable consumer advances for construction $ 416,263 $ 328,360 Estimated initial installation costs for meters 100,927 118,854 Post retirement benefit obligation 732,200 732,200 Total deferred liabilities $ 1,249,390 $ 1,179,414 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | |
Regulatory Assets [Line Items] | |
Schedule Of Deferred Charges, Or Regulatory Assets | 2017 2016 Regulatory assets: Multi-stage Energy Storage $ 0 $ 1,117,860 Regulatory studies and other 201,775 46,721 Total regulatory assets 201,775 1,164,581 Other deferred charges: NRECA pension plan prepayment 0 7,925,050 Post retirement benefit obligation 59,100 59,100 Total other deferred charges 59,100 7,984,150 Total deferred charges $ 260,875 $ 9,148,731 |
Other Equities (Tables)
Other Equities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Equities [Abstract] | |
Schedule Of Other Equities | 2017 2016 Nonoperating margins, prior to 1967 $ 23,625 $ 23,625 Donated capital 2,213,876 2,001,450 Unclaimed capital credit retirement 1 12,415,752 11,803,000 Total other equities $ 14,653,253 $ 13,828,075 1 Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska’ s unclaimed property law and have therefore reverted to Chugach. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt [Abstract] | |
Schedule Of Debt Issuance Costs Associated With Long-Term Obligations | Long-term obligations at December 31 are as follows: 2017 2016 2011 Series A Bond of 4.20% , maturing in 2031 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012 63,000,000 67,500,000 2011 Series A Bond of 4.75% , maturing in 2041 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012 147,999,998 154,166,665 2012 Series A Bond of 4.01% , maturing in 2032 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013 56,250,000 60,000,000 2012 Series A Bond of 4.41% , maturing in 2042 , with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042 88,000,000 95,000,000 2012 Series A Bond of 4.78% , maturing in 2042 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023 50,000,000 50,000,000 2017 Series A Bond of 3.43% , maturing in 2037 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2018 40,000,000 0 2016 CoBank Note, 2.58% fixed rate note maturing in 2031 , with interest and principal due quarterly beginning in 2016 40,356,000 43,776,000 Total long-term obligations $ 485,605,998 $ 470,442,665 Less current installments 26,608,667 24,836,667 Less unamortized debt issuance costs 2,669,485 2,715,745 Long-term obligations, excluding current installments $ 456,327,846 $ 442,890,253 |
Schedule Of Maturities Of Long-Term Obligations | Year ending December 31 2011 Series A Bonds 2012 Series A Bonds 2016 CoBank Note 2017 Series A Bonds Total 2018 $ 10,666,667 $ 10,750,000 $ 3,192,000 $ 2,000,000 $ 26,608,667 2019 10,666,667 10,750,000 3,192,000 2,000,000 26,608,667 2020 10,666,667 10,750,000 3,420,000 2,000,000 26,836,667 2021 10,666,667 3,750,000 3,648,000 2,000,000 20,064,667 2022 10,666,667 3,750,000 3,876,000 2,000,000 20,292,667 Thereafter 157,666,663 154,500,000 23,028,000 30,000,000 365,194,663 $ 210,999,998 $ 194,250,000 $ 40,356,000 $ 40,000,000 $ 485,605,998 |
Schedule Of Average Commercial Paper Balances Outstanding And Weighted Average Interest Rates | Month Average Balance Weighted Average Interest Rate Month Average Balance Weighted Average Interest Rate January $ 65.0 0.94 % July $ 41.1 1.40 % February $ 63.0 0.92 % August $ 41.5 1.40 % March $ 60.9 1.04 % September $ 45.7 1.40 % April $ 44.4 1.14 % October $ 48.4 1.39 % May $ 42.4 1.14 % November $ 46.0 1.39 % June $ 40.2 1.29 % December $ 48.7 1.67 % |
Schedule Of Additional Information Regarding Series A Bonds | Maturing March 15, Average Life (Years) Interest Rate Issue Amount Carrying Value 2011 Series A, Tranche A 2031 6.7 4.20 % $ 90,000 $ 63,000 2011 Series A, Tranche B 2041 11.7 4.75 % 185,000 148,000 2012 Series A, Tranche A 2032 7.2 4.01 % 75,000 56,250 2012 Series A, Tranche B 2042 15.0 4.41 % 125,000 88,000 2012 Series A, Tranche C 2042 14.7 4.78 % 50,000 50,000 2017 Series A, Tranche A 2037 10.2 3.43 % 40,000 40,000 2016 CoBank Note 2031 5.7 2.58 % 45,600 40,356 Total $ 610,600 $ 485,606 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Employee Benefit Plans [Abstract] | |
Schedule Of Information Regarding Individually Significant Pension Plans | Alaska Electrical Pension Plan 3 NRECA Retirement Security Plan 3 Employer Identification Number 92-6005171 53-0116145 Plan Number 001 333 Year-end Date December 31 December 31 Expiration Date of CBA's June 30, 2021 N/A 2 Subject to Funding Improvement Plan No No 4 Surcharge Paid N/A N/A 4 2017 2016 2015 2017 2016 2015 Zone Status Green Green Green N/A 1 N/A 1 N/A 1 Required minimum contributions None None None N/A N/A N/A Contributions (in millions) $3.3 $3.2 $3.1 $2.6 $3.5 $3.5 Contributions > 5% of total plan contributions Yes Yes Yes No No No 1 A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. 2 The CEO is the only participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through April 30 , 20 20 . 3 The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are available on Chugach’s website at www.chugachelectric.com . 4 The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the RS Plan and may change as a result of plan experience. |
Bradley Lake Hydroelectric Pr33
Bradley Lake Hydroelectric Project (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Bradley Lake Hydroelectric Project [Abstract] | |
Schedule Of Bradley Lake Information | (In thousands) Total Proportionate Share Plant in service $ 162,907 $ 49,524 Long-term debt 43,940 13,358 Interest expense 2,652 806 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies [Abstract] | |
Schedule Of Costs Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs | 2017 2016 2015 Hilcorp 88.4 % 56.9 % 30.3 % Furie 5.3 % 0.0 % 0.0 % ConocoPhillips (COP) 0.0 % 32.0 % 58.7 % AIX Energy 0.1 % 0.7 % 4.7 % ENSTAR 3.4 % 4.7 % 3.3 % Harvest (Hilcorp) Pipeline 2.1 % 3.2 % 1.6 % Miscellaneous 0.7 % 2.5 % 1.4 % |
Quarterly Results Of Operatio35
Quarterly Results Of Operations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Results Of Operations [Abstract] | |
Schedule Of Quarterly Results Of Operations | 201 7 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 62,934,930 $ 49,405,607 $ 51,554,650 $ 60,793,482 Operating Expense 52,778,100 44,850,594 48,365,752 51,223,238 Net Interest 5,575,665 5,569,961 5,535,031 5,520,479 Net Operating Margins 4,581,165 (1,014,948) (2,346,133) 4,049,765 Nonoperating Margins 157,569 207,513 201,916 211,877 Assignable Margins $ 4,738,734 $ (807,435) $ (2,144,217) $ 4,261,642 201 6 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 57,741,954 $ 45,132,973 $ 44,622,517 $ 50,250,135 Operating Expense 47,000,307 40,308,301 41,472,710 42,359,071 Net Interest 5,341,242 5,427,440 5,247,404 5,385,211 Net Operating Margins 5,400,405 (602,768) (2,097,597) 2,505,853 Nonoperating Margins 231,683 125,332 127,871 123,077 Assignable Margins $ 5,632,088 $ (477,436) $ (1,969,726) $ 2,628,930 |
Description Of Business (Detail
Description Of Business (Details) | 12 Months Ended |
Dec. 31, 2017mi | |
Description Of Business [Line Items] | |
Electrification area | 400 |
Matanuska Electric Association, Inc. [Member] | |
Description Of Business [Line Items] | |
Long-term Contract for Purchase of Electric Power, Date of Contract Extension | Apr. 30, 2015 |
Golden Valley Electric Association, Inc. [Member] | |
Description Of Business [Line Items] | |
Power contracts expiration date | Mar. 31, 2015 |
Significant Accounting Polici37
Significant Accounting Policies (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Significant Accounting Policies [Line Items] | |||
Numerator percentage of total production | 10.00% | ||
Denominator percentage of estimated remaining proved reserves | 10.00% | ||
Impairment on investments | $ 0 | $ 0 | $ 0 |
Minimum number of days past balances reviewed | 90 days | ||
Other investments | 3,100,000 | ||
Special funds | $ 1,466,010 | 907,836 | |
Accounts receivable | 35,680,680 | 33,000,919 | |
Fuel stock | 6,901,994 | 6,321,676 | |
Multiemployer plan, Prepayment amount | 7,200,000 | 7,900,000 | |
Consumer deposits | 3,700,000 | 3,300,000 | |
Customer credits | $ 1,600,000 | $ 1,900,000 | |
Weighted average capital interest percentage | 4.10% | 4.30% | 4.30% |
Grant proceeds included in public utilities property, plant and equipment carrying amount | $ 0 | $ 600,000 | |
ALASKA | |||
Significant Accounting Policies [Line Items] | |||
Special funds | $ 200,000 | ||
NRECA Retirement Plan [Member] | |||
Significant Accounting Policies [Line Items] | |||
Multiemployer plan, Prepayment amount | 7,900,000 | ||
Multiemployer plan, Prepayment amortization period | 11 years | ||
ML&P For Fuel And South Central Power Project Costs [Member] | |||
Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 1,300,000 | 1,400,000 | |
BRU Operations For Gas Sales [Member] | |||
Significant Accounting Policies [Line Items] | |||
Accounts receivable | 1,100,000 | 700,000 | |
Unbilled Retail Revenues [Member] | |||
Significant Accounting Policies [Line Items] | |||
Accounts receivable | 10,674,543 | 10,940,274 | |
Concentration Account [Member] | |||
Significant Accounting Policies [Line Items] | |||
Average balance of cash account | 6,454,809 | $ 5,897,767 | |
Funds On Deposit [Member] | |||
Significant Accounting Policies [Line Items] | |||
Restricted cash equivalents | $ 1,700,000 | ||
Maximum [Member] | CoBank, ACB (CoBank) And National Rural Utilities Cooperative Finance Corporation (NRUCFC) [Member] | |||
Significant Accounting Policies [Line Items] | |||
Cost ownership percentage | 1.00% |
Significant Accounting Polici38
Significant Accounting Policies (Schedule Of Depreciation And Amortization Rates) (Details) | 6 Months Ended | |
Dec. 31, 2017 | Jun. 30, 2017 | |
Minimum [Member] | Steam Production Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 3.03% | 3.15% |
Minimum [Member] | Hydroelectric Production Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 0.88% | 1.06% |
Minimum [Member] | Other Production Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 2.18% | 3.15% |
Minimum [Member] | Transmission Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 1.01% | 1.58% |
Minimum [Member] | Distribution Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 1.40% | 2.16% |
Minimum [Member] | General Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 1.95% | 1.57% |
Minimum [Member] | Other Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 2.75% | 2.75% |
Maximum [Member] | Steam Production Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 3.26% | 3.84% |
Maximum [Member] | Hydroelectric Production Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 2.71% | 3.00% |
Maximum [Member] | Other Production Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 3.46% | 8.85% |
Maximum [Member] | Transmission Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 10.50% | 7.86% |
Maximum [Member] | Distribution Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 10.00% | 9.63% |
Maximum [Member] | General Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 33.33% | 20.00% |
Maximum [Member] | Other Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Depreciation and amortization rates | 2.75% | 2.75% |
Significant Accounting Polici39
Significant Accounting Policies (Schedule Of Gains And Losses On Trading Securities) (Details) | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Significant Accounting Policies [Abstract] | |
Net gains and losses recognized during the period on trading securities | $ 59,182 |
Less: Net gains and losses recognized during the period on trading securities sold during the period | 0 |
Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date | $ 59,182 |
Accounting Pronouncements (Deta
Accounting Pronouncements (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member] | |
Concentration Risk [Line Items] | |
Energy percentage of revenue | 99.00% |
Fair Value Of Assets And Liab41
Fair Value Of Assets And Liabilities (Schedule Of Marketable Securities) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Bond Mutual Funds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | $ 8,109,242 | $ 7,375,381 |
Corporate Bonds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 248,335 | |
Certificates of Deposit [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 3,063,323 | 3,061,434 |
Level 1 [Member] | Bond Mutual Funds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 8,109,242 | 7,375,381 |
Level 1 [Member] | Corporate Bonds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 248,335 | |
Level 1 [Member] | Certificates of Deposit [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 3,063,323 | 3,061,434 |
Level 2 [Member] | Bond Mutual Funds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Level 2 [Member] | Corporate Bonds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | |
Level 2 [Member] | Certificates of Deposit [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Level 3 [Member] | Bond Mutual Funds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Level 3 [Member] | Corporate Bonds [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | |
Level 3 [Member] | Certificates of Deposit [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | $ 0 | $ 0 |
Fair Value Of Assets And Liab42
Fair Value Of Assets And Liabilities (Schedule Of Estimated Fair Value Of Long-Term Obligations Included In Financial Statements) (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Carrying Value [Member] | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |
Long-term obligations (including current installments) | $ 485,606 |
Level 2 [Member] | Fair Value [Member] | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |
Long-term obligations (including current installments) | $ 511,196 |
Regulatory Matters (Details)
Regulatory Matters (Details) Mcf in Millions, $ in Millions | Mar. 16, 2017 | Nov. 18, 2016USD ($) | Dec. 04, 2015Mcf | Jan. 30, 2015Mcf | Feb. 28, 2018 | Jan. 31, 2017 | Jan. 31, 2018 | Oct. 31, 2017 | Dec. 31, 2017USD ($)$ / McfeMcf |
Other Commitments [Line Items] | |||||||||
Proposed increase (decrease) in rates | $ (5.9) | ||||||||
Approved percentage increase (decrease) in rates | 1.90% | (3.00%) | |||||||
Term to finalize agreementerm to finalize agreement | 1 year | ||||||||
Beluga Power Plant [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Recovery requested | $ 11.4 | ||||||||
Beluga Power Plant, Unit 1 [Member] | Beluga Power Plant [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Recovery requested | $ 0.3 | ||||||||
Amortization period of regulatory asset | 30 months | ||||||||
Beluga Power Plant, Unit 2 [Member] | Beluga Power Plant [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Recovery requested | $ 11.1 | ||||||||
Amortization period of regulatory asset | 108 months | ||||||||
City Of Seward [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Proposed percentage increase (decrease) in rates | (4.60%) | ||||||||
City Of Seward [Member] | Total Customer Bill Basis [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Proposed percentage increase (decrease) in rates | (1.90%) | ||||||||
Retail Customers [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Proposed percentage increase (decrease) in rates | (4.70%) | ||||||||
Retail Customers [Member] | Total Customer Bill Basis [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Proposed percentage increase (decrease) in rates | (3.20%) | ||||||||
Subsequent Event [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Approved percentage increase (decrease) in rates | 0.40% | ||||||||
Hilcorp Alaska, LLC [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Expiration date of long term contract for purchase of gas supply | Mar. 31, 2018 | ||||||||
CINGSA [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Total volume of natural gas found | Mcf | 14.5 | ||||||||
Approved volume of natural gas for commercial sale | Mcf | 2 | ||||||||
Percentage of proceeds allocated | 13.00% | ||||||||
Term of notice preceding gas sales | 30 days | ||||||||
CINGSA [Member] | Minimum [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Proposed volume of natural gas for commercial sale | Mcf | 2 | ||||||||
FSS [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Percentage of proceeds allocated | 87.00% | ||||||||
Furie Operating Alaska, LLC [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Term of purchase commitment | 16 years | ||||||||
Approximate annual volume | Mcf | 1.8 | ||||||||
Furie Operating Alaska, LLC [Member] | Firm Purchases [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Commencement date of natural gas purchases | Apr. 1, 2023 | ||||||||
Expiration date of natural gas purchases | Mar. 31, 2033 | ||||||||
Furie Operating Alaska, LLC [Member] | Minimum [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Price of natural gas purchases | $ / Mcfe | 7.16 | ||||||||
Percentage of met natural gas needs | 20.00% | ||||||||
Furie Operating Alaska, LLC [Member] | Maximum [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Price of natural gas purchases | $ / Mcfe | 7.98 | ||||||||
Percentage of met natural gas needs | 25.00% | ||||||||
Eklutna Generation Station [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Expiration date of natural gas purchases | Mar. 31, 2016 | ||||||||
Gas Dispatch Agreement [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Commencement date of natural gas purchases | Apr. 1, 2016 | ||||||||
Expiration date of natural gas purchases | Mar. 31, 2017 | ||||||||
Beluga River Unit [Member] | |||||||||
Other Commitments [Line Items] | |||||||||
Deferred cost of acquisition | $ 1.5 |
Utility Plant (Details)
Utility Plant (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Other property, plant and equipment | $ 1,205,092,224 | $ 1,192,513,869 | |
Electric plant in service | 1,205,092,224 | 1,192,513,869 | |
Construction work in progress | 17,952,573 | 18,455,940 | |
Total utility plant | 1,223,044,797 | 1,210,969,809 | |
Steam Production Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Generation and processing | 101,116,277 | 101,116,277 | |
Hydroelectric Production Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Generation and processing | 33,659,129 | 33,659,129 | |
Other Production Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Generation and processing | 287,765,474 | 287,404,484 | |
Transmission Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | 296,018,078 | 282,040,969 | |
Distribution Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Distribution | 315,862,812 | 294,641,485 | |
General Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Other property, plant and equipment | 55,164,994 | 54,982,432 | |
Electric plant in service | 55,164,994 | 54,982,432 | |
Unclassified Electric Plant In Service [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Other property, plant and equipment | [1] | 60,294,349 | 83,457,981 |
Electric plant in service | [1] | 60,294,349 | 83,457,981 |
Intangible Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Transmission | [1] | 5,455,371 | 5,455,371 |
Beluga River Unit [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Other property, plant and equipment | 47,927,331 | 47,927,331 | |
Electric plant in service | 47,927,331 | 47,927,331 | |
Other [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Other- land | [1] | $ 1,828,409 | $ 1,828,409 |
[1] | Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment. Intangible plant represents Chugach's share of a Bradley Lake transmission line financed internally. Other represents Electric Plant Held for Future Use. |
Investments In Associated Org45
Investments In Associated Organizations (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Cost-method Investments [Line Items] | ||
Total investments in associated organizations | $ 8,980,410 | $ 9,349,311 |
NRUCFC Capital Term Certificates [Member] | ||
Schedule of Cost-method Investments [Line Items] | ||
Total investments in associated organizations | 6,095,980 | 6,095,980 |
CoBank [Member] | ||
Schedule of Cost-method Investments [Line Items] | ||
Total investments in associated organizations | 2,819,307 | 3,188,490 |
Other [Member] | ||
Schedule of Cost-method Investments [Line Items] | ||
Total investments in associated organizations | $ 65,123 | $ 64,841 |
Deferred Charges And Liabilit46
Deferred Charges And Liabilities (Schedule Of Deferred Charges, Or Regulatory Assets) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory Assets [Line Items] | ||
Total deferred charges | $ 32,764,065 | $ 25,140,957 |
Debt Issuance And Reacquisition Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 386,892 | 492,850 |
Refurbishment Of Transmission Equipment [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 95,679 | 104,939 |
Feasibility Studies [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 237,425 | 1,387,285 |
Cooper Lake Relicensing / Projects [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 5,149,903 | 5,280,006 |
Fuel Supply [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,801,970 | 2,005,052 |
Storm Damage [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 453,166 | 647,381 |
Other Regulatory Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 815,722 | 849,933 |
Bond Interest - Market Risk Management [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 4,884,587 | 5,365,190 |
Environmental Matters [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 978,820 | 1,024,171 |
Beluga Parts And Materials [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 10,696,210 | 0 |
Regulatory Assets Excluding Other Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 25,500,374 | 17,156,807 |
NRECA Retirement Plan [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 7,204,591 | 7,925,050 |
Post Retirement Benefit Obligation [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 59,100 | 59,100 |
Other Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | $ 7,263,691 | $ 7,984,150 |
Deferred Charges And Liabilit47
Deferred Charges And Liabilities (Schedule Of Deferred Charges, Or Regulatory Assets, Not Currently Being Recovered In Rates Charged To Consumers) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory Assets [Line Items] | ||
Total deferred charges | $ 32,764,065 | $ 25,140,957 |
Regulatory Assets Excluding Other Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 25,500,374 | 17,156,807 |
NRECA Retirement Plan [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 7,204,591 | 7,925,050 |
Post Retirement Benefit Obligation [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 59,100 | 59,100 |
Other Regulatory Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 815,722 | 849,933 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 260,875 | 9,148,731 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Multi-Stage Energy Storage [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 0 | 1,117,860 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Regulatory Studies And Other [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 201,775 | 46,721 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Regulatory Assets Excluding Other Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 201,775 | 1,164,581 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | NRECA Retirement Plan [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 0 | 7,925,050 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Post Retirement Benefit Obligation [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | 59,100 | 59,100 |
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges [Member] | ||
Regulatory Assets [Line Items] | ||
Total deferred charges | $ 59,100 | $ 7,984,150 |
Deferred Charges And Liabilit48
Deferred Charges And Liabilities (Schedule Of Deferred Credits, Or Regulatory Liabilities) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory Liabilities [Line Items] | ||
Total deferred liabilities | $ 1,249,390 | $ 1,179,414 |
Refundable Consumer Advances For Construction [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total deferred liabilities | 416,263 | 328,360 |
Estimated Initial Installation Costs For Meters [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total deferred liabilities | 100,927 | 118,854 |
Post Retirement Benefit Obligation [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total deferred liabilities | $ 732,200 | $ 732,200 |
Patronage Capital (Details)
Patronage Capital (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Patronage Capital [Line Items] | |||
Patronage capital | $ 172,928,887 | $ 169,996,436 | |
Patronage capital assigned | 166,880,163 | 164,182,580 | |
Patronage capital to be assigned to members | 6,048,724 | 5,813,856 | |
Patronage capital payable, noncurrent | 8,798,077 | 12,008,499 | |
Retirement of capital credits | 3,116,273 | 3,265,201 | $ 3,190,124 |
Excluding Homer Electric Association Retirement [Member] | |||
Patronage Capital [Line Items] | |||
Retirement of capital credits | 2,631,928 | 3,001,426 | 3,007,772 |
Excluding Matanuska Electric Association And Homer Electric Association Patronage Capital [Member] | |||
Patronage Capital [Line Items] | |||
Patronage capital payable, current | $ 57,036 | 2,014,080 | $ 2,105,440 |
Assignable Margins [Member] | |||
Patronage Capital [Line Items] | |||
Secured debt covenant restriction during period | 50.00% | ||
Homer Electric Association, Inc. [Member] | |||
Patronage Capital [Line Items] | |||
Return of patronage capital term after expiration date of Power Sales Agreement | 5 years | ||
Expiration date of power sales agreement | Dec. 31, 2013 | ||
Patronage capital, annual retirements | $ 2,000,000 | ||
Payments to retire patronage capital | 2,000,000 | ||
Patronage capital payable, noncurrent | 3,900,000 | 7,900,000 | |
Patronage capital payable, current | 2,000,000 | ||
Matanuska Electric Association, Inc. [Member] | |||
Patronage Capital [Line Items] | |||
Payments to retire patronage capital | 800,000 | ||
Patronage capital payable, noncurrent | $ 4,900,000 | $ 4,100,000 | |
Minimum [Member] | Aggregate Equities And Margins To Total Liabilities And Equities And Margins [Member] | |||
Patronage Capital [Line Items] | |||
Secured debt covenant restriction during period | 30.00% | ||
Patronage Capital [Member] | |||
Patronage Capital [Line Items] | |||
Secured debt covenant restriction at period end | 5.00% |
Other Equities (Schedule Of Oth
Other Equities (Schedule Of Other Equities) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule Of Other Equities [Line Items] | |||
Total other equities | $ 14,653,253 | $ 13,828,075 | |
Nonoperating Margins, Prior To 1967 [Member] | |||
Schedule Of Other Equities [Line Items] | |||
Total other equities | 23,625 | 23,625 | |
Donated Capital [Member] | |||
Schedule Of Other Equities [Line Items] | |||
Total other equities | 2,213,876 | 2,001,450 | |
Unclaimed Capital Credit Retirement [Member] | |||
Schedule Of Other Equities [Line Items] | |||
Total other equities | [1] | $ 12,415,752 | $ 11,803,000 |
[1] | Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska's unclaimed property law and have therefore reverted to Chugach. |
Debt (Narrative) (Details)
Debt (Narrative) (Details) | 12 Months Ended | |||
Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($) | Jan. 11, 2012USD ($) | Jan. 21, 2011USD ($) | |
Debt Instrument [Line Items] | ||||
Commercial paper | $ 50,000,000 | $ 68,200,000 | ||
Balance outstanding | $ 485,605,998 | 470,442,665 | ||
Patronage Capital [Member] | ||||
Debt Instrument [Line Items] | ||||
Secured debt covenant restriction at period end | 5.00% | |||
Indenture [Member] | Minimum [Member] | Power Sales Agreements With Members [Member] | ||||
Debt Instrument [Line Items] | ||||
Assets excluded from lien, term of contract | 3 years | |||
Indenture [Member] | Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Assets excluded from lien, term of contract | 5 years | |||
Term Loan Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Bonds issuance amount | $ 610,600,000 | |||
Commercial Paper [Member] | Minimum [Member] | ||||
Debt Instrument [Line Items] | ||||
Commercial paper repricing term | 1 day | |||
Commercial Paper [Member] | Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Commercial paper repricing term | 270 days | |||
Revolving Line Of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of credit, maximum borrowing capacity | $ 50,000,000 | |||
Line of credit, outstanding balance | $ 0 | $ 0 | ||
Line of credit, borrowing rate description | The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. | |||
Line of credit, borrowing rate | 3.00% | 2.90% | ||
Period of time the line of credit needs to be paid down for five consecutive days | 12 months | |||
Number of consecutive days debt needs to be paid down to $0 during a twelve month period | 5 days | |||
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Yield margins for interest multiplier to total interest expense | item | 1.10 | |||
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member] | Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of credit, maximum borrowing capacity | $ 150,000,000 | |||
Credit Agreement [Member] | Unsecured Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of credit, maximum borrowing capacity | $ 150,000,000 | |||
Line of credit, borrowing rate description | one month LIBOR plus 90.0 basis points, along with a 10.0 basis points facility fee (based on an A/A2/A unsecured debt rating). | |||
Line of credit, commencement date | Jun. 13, 2016 | |||
Line of credit, expiration date | Jun. 13, 2021 | |||
Facility fee | 0.10% | |||
Credit Agreement [Member] | Unsecured Credit Facility [Member] | LIBOR [Member] | ||||
Debt Instrument [Line Items] | ||||
Variable rate | 0.90% | |||
2011 Series A Bonds [Member] | Term Loan Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Bonds issuance amount | $ 275,000,000 | |||
Bonds commencement payment date | Sep. 15, 2011 | |||
Note commencement date | Jan. 21, 2011 | |||
2012 Series A Bonds [Member] | Term Loan Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Bonds issuance amount | $ 250,000,000 | |||
Bonds commencement payment date | Sep. 15, 2012 | |||
Note commencement date | Jan. 11, 2012 | |||
2016 CoBank Note [Member] | ||||
Debt Instrument [Line Items] | ||||
Bonds issuance amount | $ 45,600,000 | |||
Maturity date | Mar. 15, 2031 | |||
Interest rate | 2.58% | 2.58% | ||
Average Life (Years) | 5 years 8 months 12 days | |||
Balance outstanding | $ 40,356,000 | $ 43,776,000 | ||
2017 Series A Bonds [Member] | Term Loan Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Bonds issuance amount | $ 40,000,000 | |||
Maturity date | Mar. 15, 2037 | |||
Interest rate | 3.43% | |||
Average Life (Years) | 10 years 2 months 12 days | |||
Balance outstanding | $ 40,000,000 | $ 0 | ||
CoBank Master Loan Agreement [Member] | Term Loan Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Yield margins for interest multiplier to total interest expense | item | 1.10 | |||
Line of credit facility, first amendment date | Jun. 30, 2016 | |||
Second Amended and Restated Master Loan Agreement [Member] | Indenture [Member] | ||||
Debt Instrument [Line Items] | ||||
Yield margins for interest multiplier to total interest expense | item | 1.10 | |||
Assignable Margins [Member] | ||||
Debt Instrument [Line Items] | ||||
Secured debt covenant restriction during period | 50.00% | |||
Aggregate Equities And Margins To Total Liabilities And Equities And Margins [Member] | Minimum [Member] | ||||
Debt Instrument [Line Items] | ||||
Secured debt covenant restriction during period | 30.00% |
Debt (Schedule Of Debt Issuance
Debt (Schedule Of Debt Issuance Costs Associated With Long-Term Obligations) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 485,605,998 | $ 470,442,665 |
Less current installments | 26,608,667 | 24,836,667 |
Less unamortized debt issuance costs | 2,669,485 | 2,715,745 |
Long-term obligations, excluding current installments | 456,327,846 | 442,890,253 |
2011 Series A Bond Of 4.20% Maturing 2031 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 63,000,000 | $ 67,500,000 |
Interest rate | 4.20% | 4.20% |
Maturity year | 2,031 | |
2011 Series A Bond Of 4.75% Maturing 2041 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 147,999,998 | $ 154,166,665 |
Interest rate | 4.75% | 4.75% |
Maturity year | 2,041 | |
2012 Series A Bond Of 4.01% Maturing 2032 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 56,250,000 | $ 60,000,000 |
Interest rate | 4.01% | 4.01% |
Maturity year | 2,032 | |
2012 Series A Bond Of 4.41% Maturing 2042 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 88,000,000 | $ 95,000,000 |
Interest rate | 4.41% | 4.41% |
Maturity year | 2,042 | |
2012 Series A Bond Of 4.78% Maturing 2042 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 50,000,000 | $ 50,000,000 |
Interest rate | 4.78% | 4.78% |
Maturity year | 2,042 | |
2017 Series A Bonds [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 40,000,000 | $ 0 |
Interest rate | 3.43% | |
Maturity year | 2,037 | |
2016 CoBank Note [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Obligations | $ 40,356,000 | $ 43,776,000 |
Interest rate | 2.58% | 2.58% |
Maturity year | 2,031 |
Debt (Schedule Of Maturities Of
Debt (Schedule Of Maturities Of Long-Term Obligations) (Details) | Dec. 31, 2017USD ($) |
Debt Instrument [Line Items] | |
2,018 | $ 26,608,667 |
2,019 | 26,608,667 |
2,020 | 26,836,667 |
2,021 | 20,064,667 |
2,022 | 20,292,667 |
Thereafter | 365,194,663 |
Total long-term obligations | 485,605,998 |
2011 Series A Bonds [Member] | |
Debt Instrument [Line Items] | |
2,018 | 10,666,667 |
2,019 | 10,666,667 |
2,020 | 10,666,667 |
2,021 | 10,666,667 |
2,022 | 10,666,667 |
Thereafter | 157,666,663 |
Total long-term obligations | 210,999,998 |
2012 Series A Bonds [Member] | |
Debt Instrument [Line Items] | |
2,018 | 10,750,000 |
2,019 | 10,750,000 |
2,020 | 10,750,000 |
2,021 | 3,750,000 |
2,022 | 3,750,000 |
Thereafter | 154,500,000 |
Total long-term obligations | 194,250,000 |
2016 CoBank Note [Member] | |
Debt Instrument [Line Items] | |
2,018 | 3,192,000 |
2,019 | 3,192,000 |
2,020 | 3,420,000 |
2,021 | 3,648,000 |
2,022 | 3,876,000 |
Thereafter | 23,028,000 |
Total long-term obligations | 40,356,000 |
2017 Series A Bonds [Member] | |
Debt Instrument [Line Items] | |
2,018 | 2,000,000 |
2,019 | 2,000,000 |
2,020 | 2,000,000 |
2,021 | 2,000,000 |
2,022 | 2,000,000 |
Thereafter | 30,000,000 |
Total long-term obligations | $ 40,000,000 |
Debt (Schedule Of Average Comme
Debt (Schedule Of Average Commercial Paper Balances Outstanding And Weighted Average Interest Rates) (Details) - Commercial Paper [Member] - USD ($) $ in Millions | 1 Months Ended | |||||||||||
Dec. 31, 2017 | Nov. 30, 2017 | Oct. 31, 2017 | Sep. 30, 2017 | Aug. 31, 2017 | Jul. 31, 2017 | Jun. 30, 2017 | May 31, 2017 | Apr. 30, 2017 | Mar. 31, 2017 | Feb. 28, 2017 | Jan. 31, 2017 | |
Short-term Debt [Line Items] | ||||||||||||
Average Balance | $ 48.7 | $ 46 | $ 48.4 | $ 45.7 | $ 41.5 | $ 41.1 | $ 40.2 | $ 42.4 | $ 44.4 | $ 60.9 | $ 63 | $ 65 |
Weighted Average Interest Rate | 1.67% | 1.39% | 1.39% | 1.40% | 1.40% | 1.40% | 1.29% | 1.14% | 1.14% | 1.04% | 0.92% | 0.94% |
Debt (Schedule Of Additional In
Debt (Schedule Of Additional Information Regarding Series A Bonds) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||
Carrying Value | $ 485,605,998 | |
Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Issue Amount | 610,600,000 | |
Carrying Value | $ 485,606,000 | |
2011 Series A Bond Of 4.20% Maturing 2031 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2031 | |
Average Life (Years) | 6 years 8 months 12 days | |
Interest Rate | 4.20% | 4.20% |
Issue Amount | $ 90,000,000 | |
Carrying Value | $ 63,000,000 | |
2011 Series A Bond Of 4.75% Maturing 2041 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2041 | |
Average Life (Years) | 11 years 8 months 12 days | |
Interest Rate | 4.75% | 4.75% |
Issue Amount | $ 185,000,000 | |
Carrying Value | $ 148,000,000 | |
2012 Series A Bond Of 4.01% Maturing 2032 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2032 | |
Average Life (Years) | 7 years 2 months 12 days | |
Interest Rate | 4.01% | 4.01% |
Issue Amount | $ 75,000,000 | |
Carrying Value | $ 56,250,000 | |
2012 Series A Bond Of 4.41% Maturing 2042 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2042 | |
Average Life (Years) | 15 years | |
Interest Rate | 4.41% | 4.41% |
Issue Amount | $ 125,000,000 | |
Carrying Value | $ 88,000,000 | |
2012 Series A Bond Of 4.78% Maturing 2042 [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2042 | |
Average Life (Years) | 14 years 8 months 12 days | |
Interest Rate | 4.78% | 4.78% |
Issue Amount | $ 50,000,000 | |
Carrying Value | 50,000,000 | |
2017 Series A Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Carrying Value | $ 40,000,000 | |
2017 Series A Bonds [Member] | Term Loan Facility [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2037 | |
Average Life (Years) | 10 years 2 months 12 days | |
Interest Rate | 3.43% | |
Issue Amount | $ 40,000,000 | |
Carrying Value | $ 40,000,000 | |
2016 CoBank Note [Member] | ||
Debt Instrument [Line Items] | ||
Maturing | Mar. 15, 2031 | |
Average Life (Years) | 5 years 8 months 12 days | |
Interest Rate | 2.58% | 2.58% |
Issue Amount | $ 45,600,000 | |
Carrying Value | $ 40,356,000 |
Employee Benefit Plans (Narrati
Employee Benefit Plans (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Prepayment amount | $ 7,200,000 | $ 7,900,000 | |
Deferred compensation | $ 1,229,294 | 907,836 | |
Number of days of severance pay per year of service | 14 days | ||
Maximum number of days of severance pay | 182 days | ||
Number of years of service | 13 years | ||
NRECA Retirement Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Prepayment multiplier | 2.50% | ||
Prepayment, effect on billing rate | 25.00% | ||
Period of billing rate reduction related to prepayment | 15 years | ||
Prepayment amount | 7,900,000 | ||
Prepayment amortization period | 11 years | ||
Multiemployer Plans, Pension [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Employer contributions to benefit plan | $ 5,900,000 | 6,700,000 | $ 6,700,000 |
Union Health and Welfare Plans [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Employer contributions to benefit plan | 4,800,000 | 4,500,000 | 4,500,000 |
Non-Union Health And Welfare Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Employer contributions to benefit plan | 2,800,000 | 2,800,000 | 2,600,000 |
Money Purchase Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Employer contributions to benefit plan | $ 141,800 | $ 132,300 | $ 133,600 |
Employee Benefit Plans (Schedul
Employee Benefit Plans (Schedule Of Information Regarding Individually Significant Pension Plans) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Alaska Electrical Pension Plan [Member] | ||||
Multiemployer Plans [Line Items] | ||||
Employer Identification Number | [1] | 926,005,171 | ||
Plan Number | [1] | 1 | ||
Year-end Date | [1] | December 31 | ||
Expiration Date of CBA's | [1] | Jun. 30, 2021 | ||
Subject to Funding Improvement Plan | [1] | No | ||
Surcharge Paid | [1] | NA | ||
Zone Status | [1] | Green | ||
Required minimum contributions | [1] | None | ||
Contributions (in millions) | [1] | $ 3.3 | $ 3.2 | $ 3.1 |
Contributions > 5% of total plan contributions | [1] | Yes | ||
NRECA Retirement Plan [Member] | ||||
Multiemployer Plans [Line Items] | ||||
Employer Identification Number | [1] | 530,116,145 | ||
Plan Number | [1] | 333 | ||
Year-end Date | [1] | December 31 | ||
Subject to Funding Improvement Plan | [1],[2] | No | ||
Surcharge Paid | [1],[2] | NA | ||
Zone Status | [1],[3] | NA | ||
Required minimum contributions | [1] | N/A | ||
Contributions (in millions) | [1] | $ 2.6 | $ 3.5 | $ 3.5 |
Contributions > 5% of total plan contributions | [1] | No | ||
[1] | The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are available on Chugach's website at www.chugachelectric.com. | |||
[2] | The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the RS Plan and may change as a result of plan experience. | |||
[3] | A "zone status" determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. |
Bradley Lake Hydroelectric Pr58
Bradley Lake Hydroelectric Project (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)MWhMW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Purchased power | $ 17,301,067 | $ 15,774,733 | $ 19,599,994 |
Bradley Lake Hydroelectric Project [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Percentage share of power purchased | 30.40% | ||
Amount of committed purchased power | MW | 27.4 | ||
Threshold percentage for increasing plant costs | 25.00% | ||
Estimated increase in annual energy output | MWh | 37,000 | ||
Estimated project cost | $ 47,000,000 | ||
Estimated entitled additional energy output percentage | 39.38% | ||
Purchased power | $ 6,452,898 | $ 5,662,522 | $ 5,663,304 |
Revenue Bonds [Member] | Alaska Energy Authority [Member] | Bradley Lake Hydroelectric Project [Member] | |||
Long-term Contract for Purchase of Electric Power [Line Items] | |||
Bonds issuance amount | 166,000,000 | ||
Portion of outstanding debt | 16,300,000 | ||
Possible annual expenditures upon default | $ 6,000,000 |
Bradley Lake Hydroelectric Pr59
Bradley Lake Hydroelectric Project (Schedule Of Bradley Lake Information) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Long-term Contract for Purchase of Electric Power [Line Items] | ||||||||||||
Plant in service | $ 1,223,044,797 | $ 1,210,969,809 | $ 1,223,044,797 | $ 1,210,969,809 | ||||||||
Long-term debt | 485,605,998 | 485,605,998 | ||||||||||
Interest expense | $ 5,575,665 | $ 5,569,961 | $ 5,535,031 | $ 5,520,479 | $ 5,341,242 | $ 5,427,440 | $ 5,247,404 | $ 5,385,211 | $ 22,201,136 | $ 21,401,297 | $ 21,814,445 | |
Bradley Lake Hydroelectric Project [Member] | Alaska Energy Authority [Member] | ||||||||||||
Long-term Contract for Purchase of Electric Power [Line Items] | ||||||||||||
Plant in service | 162,907,000 | $ 162,907,000 | ||||||||||
Long-term debt | 43,940,000 | 43,940,000 | ||||||||||
Interest expense | 2,652,000 | |||||||||||
Bradley Lake Hydroelectric Project [Member] | Alaska Energy Authority [Member] | Proportionate Share [Member] | ||||||||||||
Long-term Contract for Purchase of Electric Power [Line Items] | ||||||||||||
Plant in service | 49,524,000 | 49,524,000 | ||||||||||
Long-term debt | $ 13,358,000 | 13,358,000 | ||||||||||
Interest expense | $ 806,000 |
Eklutna Hydroelectric Project (
Eklutna Hydroelectric Project (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||
Net utility plant | $ 707,548,485 | $ 714,871,678 | $ 707,548,485 | $ 714,871,678 | |||||||
Accumulated depreciation | 515,496,312 | 496,098,131 | 515,496,312 | 496,098,131 | |||||||
Total operating expenses | $ 52,778,100 | $ 44,850,594 | $ 48,365,752 | $ 51,223,238 | 47,000,307 | $ 40,308,301 | $ 41,472,710 | $ 42,359,071 | $ 197,217,684 | 171,140,389 | $ 188,791,558 |
Eklutna Hydroelectric Project [Member] | |||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||
Percentage ownership | 30.00% | 30.00% | |||||||||
Net utility plant | $ 3,967,933 | 4,229,167 | $ 3,967,933 | 4,229,167 | |||||||
Accumulated depreciation | $ 2,591,717 | $ 2,442,175 | 2,591,717 | 2,442,175 | |||||||
Total operating expenses | $ 403,511 | $ 532,678 | $ 689,501 | ||||||||
Matanuska Electric Association, Inc. [Member] | Eklutna Hydroelectric Project [Member] | |||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||
Percentage ownership | 17.00% | 17.00% | |||||||||
Municipal Light & Power [Member] | Eklutna Hydroelectric Project [Member] | |||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||
Percentage ownership | 53.00% | 53.00% |
Beluga River Unit (Narrative) (
Beluga River Unit (Narrative) (Details) | Feb. 04, 2016USD ($)aMcf | Dec. 31, 2017USD ($)Mcf | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($)Mcf | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)miMcf | Dec. 31, 2016USD ($)Mcf | Dec. 31, 2015USD ($) |
Business Acquisition [Line Items] | ||||||||||||
Revenue | $ 62,934,930 | $ 49,405,607 | $ 51,554,650 | $ 60,793,482 | $ 57,741,954 | $ 45,132,973 | $ 44,622,517 | $ 50,250,135 | $ 224,688,669 | $ 197,747,579 | $ 216,421,152 | |
Beluga River Unit [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Date of Purchase and Sale Agreement | Feb. 4, 2016 | |||||||||||
Total purchase price | $ 148,000,000 | |||||||||||
Cash consideration | $ 44,400,000 | |||||||||||
Working interest ownership percentage | 30.00% | 10.00% | 10.00% | |||||||||
Number of lease acres | a | 15,500 | |||||||||||
Number of lease acres in Unit / Participating Area | a | 8,200 | |||||||||||
Number of lease acres held by Unit | a | 7,300 | |||||||||||
Number of miles from Anchorage | mi | 35 | |||||||||||
Acquisition costs | $ 1,500,000 | $ 1,500,000 | ||||||||||
Amount of gas acquired | Mcf | 69,099 | 8 | 84 | 8 | 84 | |||||||
Revenue | $ 6,600,000 | $ 2,800,000 | ||||||||||
Lifted amount of gas during the period | Mcf | 1,400,000 | |||||||||||
Lifted amount of gas in proven developed reserves | Mcf | 3,100,000 | 3,100,000 | ||||||||||
Remaining amount of gas in proven developed reserves | Mcf | 25,100,000 | 25,100,000 | ||||||||||
Municipal Light & Power [Member] | Beluga River Unit [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Working interest ownership percentage | 70.00% | 56.70% | 56.70% | |||||||||
ConocoPhillips (COP) [Member] | Beluga River Unit [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Working interest ownership percentage | 33.30% | 33.30% | ||||||||||
ConocoPhillips (COP) [Member] | Deep Oil Resources [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Working interest ownership percentage | 67.00% | |||||||||||
Hilcorp Alaska, LLC [Member] | Beluga River Unit [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Working interest ownership percentage | 33.30% | 33.30% | ||||||||||
ENSTAR [Member] | ConocoPhillips (COP) [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Expiration year of Gas Sale and Purchase Agreement | 2,017 |
Commitments And Contingencies62
Commitments And Contingencies (Narrative) (Details) Mcf in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)$ / kWhcontractitemMcf | Dec. 31, 2016USD ($) | |
Other Commitments [Line Items] | ||
Contingency accruals | $ 0 | |
Percentage of power generated from gas | 81.00% | 77.00% |
Patronage capital payable, noncurrent | $ 8,798,077 | $ 12,008,499 |
Other current liabilities | $ 7,079,821 | $ 3,234,586 |
Regulatory initial cost charge per KWH | $ / kWh | 0.000626 | |
Regulatory current cost charge per KWH | $ / kWh | 0.000899 | |
Percentage of three year average of gross retail revenue to be spent on underground lines | 2.00% | |
Average of gross revenue to determine expenditure for underground lines | 3 years | |
Percentage of retail bill collected to move existing overhead lines underground | 2.00% | |
Beluga Power Plant [Member] | ||
Other Commitments [Line Items] | ||
Percentage of power generated from gas | 14.00% | 9.00% |
Southcentral Power Project Plant [Member] | ||
Other Commitments [Line Items] | ||
Percentage of power generated from gas | 81.00% | 88.00% |
Homer Electric Association, Inc. [Member] | ||
Other Commitments [Line Items] | ||
Power contracts expiration date | Dec. 31, 2013 | |
Patronage capital, annual retirements | $ 2,000,000 | |
Payments to retire patronage capital | 2,000,000 | |
Patronage capital payable, noncurrent | 3,900,000 | $ 7,900,000 |
Patronage capital payable, current | 2,000,000 | |
Matanuska Electric Association, Inc. [Member] | ||
Other Commitments [Line Items] | ||
Payments to retire patronage capital | 800,000 | |
Patronage capital payable, noncurrent | $ 4,900,000 | 4,100,000 |
Hilcorp Alaska, LLC [Member] | ||
Other Commitments [Line Items] | ||
Commencement date of long term contract for purchase of gas supply | Jan. 1, 2015 | |
Expiration date of long term contract for purchase of gas supply | Mar. 31, 2018 | |
Hilcorp Alaska, LLC, Purchase Commitment Amendment 1 [Member] | ||
Other Commitments [Line Items] | ||
Commencement date of long term contract for purchase of gas supply | Sep. 15, 2014 | |
Expiration date of long term contract for purchase of gas supply | Mar. 31, 2019 | |
Percentage Of Met Natural Gas Needs | 100.00% | |
Hilcorp Alaska, LLC, Purchase Commitment Amendment 2 [Member] | ||
Other Commitments [Line Items] | ||
Commencement date of long term contract for purchase of gas supply | Sep. 8, 2015 | |
Expiration date of long term contract for purchase of gas supply | Mar. 31, 2023 | |
Estimated amount of gas under contract | Mcf | 60 | |
Percentage Of Met Natural Gas Needs | 100.00% | |
Marathon Alaska Production, LLC [Member] | ||
Other Commitments [Line Items] | ||
Commencement date of long term contract for purchase of gas supply | Apr. 1, 2011 | |
Expiration date of long term contract for purchase of gas supply | Mar. 31, 2023 | |
Estimated amount of gas under contract | Mcf | 49 | |
Percentage Of Met Natural Gas Needs | 100.00% | |
Number of contract extensions | contract | 2 | |
Moving Overhead Lines Underground [Member] | ||
Other Commitments [Line Items] | ||
Other current liabilities | $ 4,206,223 | $ 2,507,482 |
International Brotherhood of Electrical Workers [Member] | ||
Other Commitments [Line Items] | ||
Percentage of employees belonging to unions | 70.00% | |
Number of collective bargaining agreements | item | 3 | |
Expiration date of collective bargaining agreements | Jun. 30, 2021 | |
Hotel Employees and Restaurant Employees [Member] | ||
Other Commitments [Line Items] | ||
Number of collective bargaining agreements | item | 1 |
Commitments And Contingencies63
Commitments And Contingencies (Schedule Of Cost Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs) (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Hilcorp Alaska, LLC [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 0.10% | 0.70% | 4.70% |
Furie Operating Alaska, LLC [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 5.30% | 0.00% | 0.00% |
ConocoPhillips (COP) [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 88.40% | 56.90% | 30.30% |
AIX Energy, LLC [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 0.00% | 32.00% | 58.70% |
ENSTAR [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 3.40% | 4.70% | 3.30% |
Harvest (Hilcorp) Pipeline [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 2.10% | 3.20% | 1.60% |
Miscellaneous [Member] | |||
Other Commitments [Line Items] | |||
Cost of fuel purchased and transported as a percentage of total fuel costs | 0.70% | 2.50% | 1.40% |
Quarterly Results Of Operatio64
Quarterly Results Of Operations (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Results Of Operations [Abstract] | |||||||||||
Operating revenues | $ 62,934,930 | $ 49,405,607 | $ 51,554,650 | $ 60,793,482 | $ 57,741,954 | $ 45,132,973 | $ 44,622,517 | $ 50,250,135 | $ 224,688,669 | $ 197,747,579 | $ 216,421,152 |
Operating expenses | 52,778,100 | 44,850,594 | 48,365,752 | 51,223,238 | 47,000,307 | 40,308,301 | 41,472,710 | 42,359,071 | 197,217,684 | 171,140,389 | 188,791,558 |
Net interest | 5,575,665 | 5,569,961 | 5,535,031 | 5,520,479 | 5,341,242 | 5,427,440 | 5,247,404 | 5,385,211 | 22,201,136 | 21,401,297 | 21,814,445 |
Net operating margins | 4,581,165 | (1,014,948) | (2,346,133) | 4,049,765 | 5,400,405 | (602,768) | (2,097,597) | 2,505,853 | 5,269,849 | 5,205,893 | 5,815,149 |
Nonoperating margins | 157,569 | 207,513 | 201,916 | 211,877 | 231,683 | 125,332 | 127,871 | 123,077 | 778,875 | 607,963 | 687,703 |
Assignable margins | $ 4,738,734 | $ (807,435) | $ (2,144,217) | $ 4,261,642 | $ 5,632,088 | $ (477,436) | $ (1,969,726) | $ 2,628,930 | $ 6,048,724 | $ 5,813,856 | $ 6,502,852 |