SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number 33-42125
Chugach Electric Association, Inc.
(Exact name of registrant as specified in its charter)
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Alaska |
| 92-0014224 |
(State or other jurisdiction of |
| (I.R.S. Employer |
incorporation or organization) |
| Identification No.) |
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5601 Electron Dr., Anchorage, Alaska |
| 99518 |
(Address of principal executive offices) |
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Registrant’s telephone number, including area code |
| (907) 563-7494 |
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class |
| Name of each exchange on which registered |
N/A |
| N/A |
Securities registered pursuant to Section 12(g) of the Act:
N/A
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
☐ Yes ☒ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
☒ Yes ☐ No
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
☐ Yes ☒ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
☒ Yes ☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | ☐ |
| Accelerated filer | ☐ |
Non-accelerated filer | ☒ |
| Smaller reporting company | ☐ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
☐Yes ☒ No
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. N/A
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the last practicable date. NONE
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CHUGACH ELECTRIC ASSOCIATION, INC.
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Table of Contents | |||||
Page | |||||
| Item 1. | 2 | |||
| Item 1A. | 9 | |||
| Item 1B. | 13 | |||
| Item 2. | 14 | |||
| Item 3. | 22 | |||
| Item 4. | 22 | |||
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| Item 5. | 22 | |||
| Item 6. | 23 | |||
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 24 | ||
| Item 7A. | 40 | |||
| Item 8. | 41 | |||
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 81 | ||
| Item 9A. | 81 | |||
| Item 9B. | 82 | |||
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| Item 10. | 82 | |||
| Item 11. | 86 | |||
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 92 | ||
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | 92 | ||
| Item 14. | 93 | |||
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| Item 15. | 94 | |||
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| 105 |
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CAUTION REGARDING FORWARD-LOOKING STATEMENTS
Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. Chugach Electric Association, Inc. (Chugach) undertakes no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained in this report, except as required by law.
General
Chugach was organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations (Internal Revenue Code 501(c)(12)), cooperatives are structured to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity other than for reasonable reserves and margins. Today, cooperatives in general operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members’ equity is not considered an investment, a cooperative’s objectives and policies are oriented to serving member interests, rather than maximizing return on investment.
Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC). The information on Chugach’s website is not a part of this Annual Report on Form 10-K. Chugach’s website also provides a link to the SEC’s website at http://www.sec.gov.
Chugach is the largest electric utility in Alaska. We are 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. Neither Chugach nor any other electric utility in Alaska’s Railbelt has any connection to the electric grid of the continental United States or Canada. Our principal executive offices are located at 5601 Electron Drive, Anchorage, Alaska 99518. Our telephone number is (907) 563-7494.
Chugach is a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code). Chugach’s hydroelectric project is licensed by the Federal Energy Regulatory Commission (FERC). As such, Chugach is subject to FERC reporting requirements and our accounting records conform to the Uniform System of Accounts as prescribed by FERC. In lieu of state and local ad valorem, income and excise taxes, Alaska electric cooperatives must pay a gross revenue tax to the State of Alaska at the rate of $0.0005 per kilowatt-hour (kWh) of electricity sold in the retail market during the preceding year. This tax is accrued monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000732 per kWh of retail electricity sold. The RCC is assessed
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to fund the operations of the Regulatory Commission of Alaska (RCA) and is collected monthly and remitted to the State of Alaska quarterly. We also collect sales tax on retail electricity sold to consumers in Whittier, seasonally (April through September), and in the Kenai Peninsula Borough, monthly. This tax is remitted to the City of Whittier monthly and to the Kenai Peninsula Borough quarterly. These taxes are a direct pass-through to consumer bills and therefore do not impact our margins.
We had 291 employees as of March 8, 2016. 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 an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA have been renewed through June 30, 2017. The three CBA provide for wage increases in all years and include health and welfare premium cost sharing provisions. The HERE contract has been renewed through June 30, 2016, and provides for wage increases in all years. We believe our relationship with our employees is good.
Our members are the consumers of the electricity sold by us. As of December 31, 2015, we had one wholesale customer, 68,543 retail members, and approximately 83,383 service locations, including idle services. No individual retail customer receives more than five percent of our power. Our customers’ requirements for capacity and energy generally peak in fall and winter as home heating and lighting needs rise and then decline in the spring and summer as the weather becomes milder and daylight hours increase.
We supply power to the City of Seward (Seward) as a wholesale customer, and provided most of the power requirements of Matanuska Electric Association, Inc. (MEA) and Homer Electric Association, Inc. (HEA) through the expiration of their contracts on April 30, 2015, and December 31, 2013, respectively. 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.
Our customers are billed on a monthly basis per a tariffed rate for electrical power consumed during the preceding period. Billing rates are approved by the RCA, see “Item 1 – Business – Rate Regulation and Rates.” Base rates (derived on the basis of historic cost of service including margins) are established to generate revenues in excess of current period costs in any year and such excess is designated on our Statements of Revenues, Expenses and Patronage Capital as “assignable margins.” Retained assignable margins are designated on our balance sheet as “patronage capital” that is assigned to each member on the basis of patronage. Patronage capital is held for the account of the members without interest and returned when the Chugach Board of Directors deems it appropriate to do so.
During 2015, we had 602.7 megawatts (MW) of installed generating capacity (rated capacity) provided by 18 generating units at our five owned power plants: Beluga Power Plant, International Station Power Plant (historically known as “IGT”), Cooper Lake Hydroelectric Project, Southcentral Power Project (SPP), in which we own a 70% interest, and Eklutna Hydroelectric Project, in which we own a 30% interest. In April of 2015, Beluga Unit 8 was retired representing 53.0 MW of capacity. In August of 2015, IGT Unit 3 was retired representing 18.5 MW of capacity. Therefore, we had 531.2 MW of installed generating capacity consisting of 16 generating units at December 31, 2015. Of the 602.7 MW of installed generating capacity, approximately 79% was fueled by natural gas. Following the retirement of Beluga Unit 8 and IGT Unit 3, approximately 87% was fueled by natural gas, which we purchased under gas contracts. The rest of our owned generating resources were hydroelectric facilities. During 2015, 86% of Chugach’s power, including
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purchased power, was generated from gas. Of that gas-fired generation, 61% took place at SPP and 30% took place at Beluga. The SPP furnishes up to 200.2 MW of capacity; Chugach owns 70% of this plant’s output and Anchorage Municipal Light & Power (ML&P) owns the remaining 30%. The Bradley Lake Hydroelectric Project, which is not owned by Chugach, provides up to 27.4 MW, as currently operated, for our retail customers and up to 0.9 MW for our remaining wholesale customer. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” In addition, we purchase up to 17.6 MW from Fire Island Wind, LLC (FIW), annually, and in an agreement entered into with MEA for a four month period ending April 30, 2015, we purchased up to 171 MW from the Eklutna Generation Station (EGS). We operate 1,706 miles of distribution line and 407 miles of transmission line, which includes Chugach’s share of the Eklutna transmission line. For the year ended December 31, 2015, we sold 1.6 billion kWh of electrical power.
Customer Revenue from Sales
The following table shows the megawatt-hour (MWh) energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2015:
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| MWh |
| 2015 Revenues |
| Percent of Sales Revenue | ||
Direct retail sales: |
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Residential | 509,824 |
| $ | 85,849,646 |
| 41 | % |
Commercial | 623,603 |
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| 84,297,816 |
| 40 | % |
Total | 1,133,427 |
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| 170,147,462 |
| 81 | % |
Wholesale sales: |
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MEA | 275,362 |
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| 26,177,627 |
| 13 | % |
Seward | 61,347 |
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| 4,770,129 |
| 2 | % |
Total | 336,709 |
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| 30,947,756 |
| 15 | % |
Economy energy/other1 | 105,815 |
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| 8,150,983 |
| 4 | % |
Total from sales | 1,575,951 |
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| 209,246,201 |
| 100 | % |
Miscellaneous energy revenue |
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| 7,174,951 |
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Total energy revenues |
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| $ | 216,421,152 |
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1 Economy energy/other includes sales to GVEA and ML&P. |
Retail Service Territory
Our retail service area covers most of Anchorage, excluding downtown Anchorage, as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula westward to Tyonek, including Fire Island, and eastward to Whittier.
Retail Customers
As of December 31, 2015, we had 68,543 members receiving power from approximately 83,383 services, including idle services (some members are served by more than one service). Our customers are a mix of urban and suburban. The urban nature of our customer base means that we have a relatively high customer density per line mile. Higher customer density means that fixed costs can be spread over a greater number of customers. As a result of lower average costs
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attributable to each customer, we benefit from a greater stability in revenue, as compared to a less dense distribution system in which each individual customer would have a more significant impact on operating results. For the past five years no retail customer accounted for more than five percent of our revenues. The revenue contributed by retail customers for the years ended December 31, 2015, 2014 and 2013 is discussed in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year ended December 31, 2015, compared to the year ended December 31, 2014, and the year ended December 31, 2014, compared to the year ended December 31, 2013 – Revenues.
Wholesale Customers
We are the principal supplier of power to Seward under a wholesale power contract. We were the principal supplier of power to MEA and HEA through April 30, 2015, and December 31, 2013, respectively. Our wholesale power contracts, including the fuel and purchased power components, contributed $30.9 million, $75.5 million, and $108.0 million in revenues for the years ended December 31, 2015, 2014 and 2013, respectively.
MEA
We had a power sales contract with MEA, which was in effect through December 31, 2014. In 2004, pursuant to terms of this contract, MEA communicated to Chugach that MEA did not desire to renew, extend or modify the agreement. MEA indicated it would follow the path its membership most favored and move forward with plans to build its own generation plant.
On August 12, 2014, MEA notified Chugach that their newly constructed power plant, the EGS, would not be completed by January 1, 2015. On September 30, 2014, Chugach entered into an Interim Power Sales Agreement to provide MEA with all demand and energy requirements on a firm basis based on existing tariff rates for a minimum one quarter period beginning on January 1, 2015, and ending on March 31, 2015.
On December 22, 2014, Chugach entered into a Dispatch Services Agreement with MEA to provide electric and natural gas dispatch services for EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for MEA’s share of the Eklutna Hydroelectric Project effective on or about April 1, 2015. The term of the agreement expires on March 31, 2016, unless extended by MEA through March 31, 2017.
On March 31, 2015, Chugach entered into a Memorandum of Understanding (MOU) with MEA to extend the Interim Power Sales Agreement for one month while MEA continued to prepare its EGS and supervisory control and data acquisition (SCADA) system for commercial operation. This MOU also delayed the implementation of the Dispatch Services Agreement to May 1, 2015. The Interim Power Sales Agreement with MEA expired on April 30, 2015. Sales to MEA represented approximately 17%, 33%, and 27% of Chugach’s total energy sales for the years ended December 31, 2015, 2014, and 2013, respectively.
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 $3.2 million and $2.3 million at December 31, 2015, and 2014, respectively.
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HEA
We had a power sales contract with Alaska Electric and Energy Cooperative, Inc. (AEEC) for firm, partial-requirement sales to HEA through December 31, 2013. Sales to HEA represented approximately 16% of Chugach’s total energy sales for the year ended December 31, 2013.
On July 12, 2011, Chugach, AEEC and HEA entered into an Asset Purchase and Sale Agreement whereby Chugach agreed to sell and AEEC agreed to purchase the Bernice Lake Power Plant located in Nikiski, Alaska. The sale included associated transmission substation facilities located on the premises. The Bernice Lake Power Plant facility is located on land that was previously leased to Chugach by HEA.
Associated with the Asset Purchase and Sale Agreement described above, Chugach entered into an Agreement for Sale of Electric Capacity with AEEC and HEA (Capacity Agreement). The Capacity Agreement was a purchased power agreement that gave Chugach the right to purchase the capacity and related energy from the Bernice Lake Power Plant from the closing date of the sale of the facility (Asset Purchase and Sale Agreement) to AEEC through December 31, 2013. This agreement further allowed Chugach to sell the Bernice Lake Power Plant and simultaneously ensure system retail and wholesale deliverability requirements were met through December 31, 2013.
Chugach continued to dispatch the power plant until the expiration of its power sales agreement with HEA, therefore, in December of 2013, Chugach recognized the gain associated with this sale which amounted to $6.4 million.
HEA’s resource requirements are now provided by AEEC’s Nikiski cogeneration facility, the Bernice Lake Power Plant and AEEC’s contract rights to receive power from the Bradley Lake Hydroelectric Project for the benefit of HEA. We also had a dispatch agreement with AEEC to operate the Nikiski unit as a Chugach system resource, which ended on December 31, 2013.
In 2007, 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 related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The agreement was contingent on the RCA accepting the parties’ settlement agreement in Docket U-06-134, which occurred on August 9, 2007. HEA’s patronage capital payable was $7.9 million at December 31, 2015, and by agreement returned to HEA by December 31, 2018.
Seward
We currently provide nearly all the power needs of the City of Seward. Sales to Seward represented approximately 4%, 3%, and 2% of Chugach’s total energy sales for the years ended December 31, 2015, 2014, and 2013, respectively. We entered into a power sales agreement (2006 Agreement) with the City of Seward, effective June 1, 2006, with a term of five years with two automatic five-year extensions, after RCA review, unless notice of termination is given by either party. On May 6, 2011, Chugach submitted a request to the RCA to extend the term of the 2006 Agreement to December 31, 2016. The RCA issued a letter order on May 26, 2011, approving the extension. The 2006 Agreement is an interruptible, all-requirements/no generation capacity reserves contract. It has many of the attributes of firm service, especially in the requirement that so long as Chugach has sufficient power available, it must meet Seward’s needs for power. However, service is interruptible because Chugach is under no obligation to supply or plan for generation capacity reserves to supply Seward and there is no limit on the number of times or hours per year that the supply can be
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interrupted. Counterbalancing this is the requirement that Chugach must provide power to Seward if Chugach has the power available after first meeting its obligations to its retail customers for whom Chugach has an obligation to provide reserves. The price under the 2006 Agreement reflects the reduced level of service because no costs of generation in excess of that needed to meet the system peak is assigned to Seward.
Economy Customers
From 1989 through March 31, 2015, we have sold economy (non-firm) energy to GVEA, which used that energy to serve its own loads.
In that agreement, sales were made under the terms and conditions of Chugach’s economy energy sales tariff. The price to GVEA included the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin. Chugach also entered into specific gas supply arrangements to make economy energy sales to GVEA. Non-firm sales to GVEA were 96,259 MWh, 358,988 MWh and 351,390 MWh for 2015, 2014, and 2013, respectively.
Rate Regulation and Rates
The RCA regulates our rates. We seek changes in our base rates by submitting Simplified Rate Filings (SRF) or through general rate cases filed with the RCA on an as-needed basis. Chugach’s base rates, whether set under a general rate case or a SRF, are established to allow the continued recovery 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.
Alaska Statute 42.05.175 requires the RCA to issue a final order no later than 15 months after a complete tariff filing is made for a tariff filing that changes a utility’s revenue requirement or rate design. It is within the RCA’s authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered.
The RCA has exclusive regulatory control of our retail and wholesale rates, subject to appeal to the Alaska courts. The regulatory environment in Alaska requires cooperatives to use a debt service coverage approach to ratemaking. Times Interest Earned Ratio (TIER) is designed to ensure Chugach maintains a coverage ratio that allows Chugach to remain in compliance with its debt covenants. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. Under Alaska law, a cooperative utility that is negotiating to enter into a mortgage or other debt instrument that provides for a TIER greater than the ratio the RCA most recently approved for that cooperative must submit the mortgage or debt instrument to the RCA before the instrument takes effect. The rate covenants contained in the instruments governing our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.
We expect to continue to recover changes in our fuel and purchased power expenses through routine quarterly filings with the RCA, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations – Overview – Rate Regulation and Rates – Fuel and Purchased Power Recovery.”
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The Second Amended and Restated Indenture of Trust (the Indenture), which became effective January 20, 2011, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The Amended and Restated Master Loan Agreement with CoBank, ACB (CoBank) which became effective January 19, 2011, also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. The Amended Unsecured Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which governs the unsecured credit facility Chugach may use to meet its obligations under its Commercial Paper Program, also requires Chugach to maintain a minimum margins for interest of at least 1.10 times interest charges for each fiscal year.
For the years ended December 31, 2015, 2014 and 2013, our Margins for Interest/Interest (MFI/I) was 1.29, 1.28, and 1.43, respectively. For the same periods, our TIER was 1.30, 1.29, and 1.43, respectively. The higher MFI/I and TIER in 2013 was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.
Our Service Areas and Local Economy
Our service areas and the service area of our wholesale customer reside within the Alaska Railbelt region of Alaska which is linked by the Alaska Railroad.
Anchorage is located in the Southcentral region of Alaska and is the trade, service, medical and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, medical, financial and educational facilities, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.
Seward is a city located at the head of Resurrection Bay on the Kenai Peninsula. Seward, which is approximately 127 miles south of Anchorage, is a major fisheries port and also serves as the ocean terminus of the Alaska Railroad. Seward’s other major industry is tourism.
Sales Forecasts
The following table sets forth our projected sales forecasts for the next five years:
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Sales (MWh) |
| 2016 |
| 2017 |
| 2018 |
| 2019 |
| 2020 |
Retail |
| 1,143,657 |
| 1,143,657 |
| 1,143,657 |
| 1,143,657 |
| 1,143,657 |
Wholesale |
| 61,382 |
| 61,382 |
| 61,382 |
| 61,382 |
| 61,382 |
Total |
| 1,205,039 |
| 1,205,039 |
| 1,205,039 |
| 1,205,039 |
| 1,205,039 |
Energy sales are expected to remain flat due to slow economic growth and progress in energy efficiency and conservation from 2016 to 2020. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could affect a change in the projected sales forecast.
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Chugach’s consolidated financial results will be impacted by weather, the economy of our service territory, fuel availability and prices, and the decisions of regulatory agencies. Our creditworthiness will be affected by national and international monetary trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition, results of operations and cash flows. The statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Financing
On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper Program. Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement to update the pricing and extend the term. The Amended Unsecured Credit Agreement now expires on November 17, 2016. Chugach is expected to continue to issue commercial paper in 2016, as needed, however, the requirement for short-term borrowing has decreased. For additional information concerning our Commercial Paper Program, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt – Commercial Paper.”
No assurance can be given that Chugach will be able to continue to access the commercial paper market. If Chugach were unable to access that market, the Amended Unsecured Credit Agreement would be utilized to support Chugach’s Commercial Paper Program. Global financial markets and economic conditions have been volatile due to a variety of factors. As a result, the cost of raising money in the debt capital markets could increase while the availability of funds from those markets could diminish.
Credit Ratings
Changes in our credit ratings could affect our ability to access capital. We maintain a rating from Standard & Poor's Rating Services (S&P) and Fitch Ratings (Fitch) of "A-" (Stable) and "A" (Stable), respectively. S&P and Moody's currently rate our commercial paper at "A-1" and "P-2", respectively. If these agencies were to downgrade our ratings, particularly below investment grade, we may be required to pay higher interest rates on financings which we need to undertake in the future, and our potential pool of investors and funding sources could decrease.
War, acts and threats of terrorism, sabotage, cyber security breach, natural disaster, and other significant events could adversely affect our operations
We cannot predict the impact that any future terrorist attacks, sabotage, or natural disaster may have on the energy industry in general, or on our business in particular. Any such event may affect our operations in unpredictable ways, such as changes in insurance markets. Furthermore, electric generation, transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror, sabotage, or cyber security breach. The physical or cyber security compromise of our facilities could adversely affect our ability to manage our facilities effectively. Chugach has not experienced any disruptions or significant costs associated with intentional attacks or unauthorized access to any of our systems. Chugach has numerous programs in place to safeguard our operating systems and the personal information of our customers and employees.
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Pension Plans
We participate in the Alaska Electrical Pension Fund (AEPF). The AEPF is a multiemployer pension plan to which we make fixed, per employee contributions through our collective bargaining agreement with the IBEW, which covers our IBEW-represented workforce. We do not have control over the AEPF. Chugach receives information concerning its funding status annually. There is no contingent liability at this time. If a funding shortfall in the AEPF exists, we may incur a contingent withdrawal liability.
We also participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (RS Plan), a multi-employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. All employees not covered by a union agreement become participants in the RS Plan. We do not have control over the RS Plan. The RS Plan updates contribution rates on an annual basis to maintain the health of the plan under the plans rules allowed by the Employee Retirement Income Security Act (ERISA). The RS Plan’s funding status is governed by plan rules as provided by ERISA. Chugach receives information concerning its funding status biannually. The RS Plan is not subject to the Pension Protection Act of 2006 under a permanent exemption from Congress as of December 16, 2014.
Equipment Failures and Other External Factors
The generation and transmission of electricity requires the use of expensive and complex equipment. While we have maintenance programs for existing equipment, along with a contractual service plan in place for SPP, generating plants are subject to unplanned outages because of equipment failure or environmental disasters. In the event of unplanned outages, we must acquire power, which is not otherwise available from the fleet of Chugach generators, from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. The fuel and purchased power rate adjustment process allows Chugach to recover current purchased power costs and to recover under-recoveries or refund over-recoveries with a three-month lag. If Chugach were to materially under-recover purchased power costs due to an unplanned outage, we would normally seek an increase in the rate adjustment to recover those costs at the time of the next quarterly fuel and purchased power rate adjustment filing. As a result, cash flows may be impacted due to the lag in payments for purchased power costs and the corresponding collection of those costs from customers. To the extent the regulatory process does not provide for the timely recovery of purchased power costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.
Fuel Supply
In 2015, 86% of our power was generated from natural gas. Our primary suppliers of natural gas are ConocoPhillips and Hilcorp. Chugach currently has gas contracts in place to fill up to 100% of Chugach’s needs through March 31, 2023. Chugach also has agreements with Cook Inlet Energy (CIE) and AIX Energy, LLC, which provide a structure to purchase supplemental gas adding diversity in Chugach’s sources of natural gas to meet system load requirements.
10
The State of Alaska’s Department of Natural Resources (DNR) published a study in September of 2015, “Updated Engineering Evaluation of Remaining Cook Inlet Gas Reserves,” to provide an estimate of Cook Inlet’s gas supply. The study estimated there are 1,183 Bcf of proved and probable reserves remaining in Cook Inlet’s legacy fields. This is higher than the 2009 DNR study estimate of 1,142 Bcf. Effectively, Cook Inlet gas supply has slightly increased from 2009. The 2015 DNR estimate does not include reserves from a large gas field under development by Furie Operating Alaska, LLC (Furie) and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has achieved production. The platform and other production facilities are designed for up to 200 million cubic feet (MMcf) per day. Other gas producers are actively developing gas supplies in the Cook Inlet. Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.
Since 2012, Hilcorp has acquired significant oil and gas assets in the Cook Inlet and reworked those assets to increase production, and several other developers have brought new sources of gas production online. As a result, local gas production trends have changed and indicate a need for an export option to support ongoing development. On December 12, 2013, ConocoPhillips announced that it filed an application with the United States Department of Energy (DOE) to resume liquefied natural gas (LNG) exports from Alaska. The application is for a two-year export authorization to export about 40 Bcf of gas per year as LNG. On February 28, 2014, the DOE approved the application to ship 40 Bcf of gas as LNG over a two-year period to countries which have free trade agreements with the US. On February 9, 2016, the DOE approved another ConocoPhillips application with similar terms. ConocoPhillips exported approximately 16.5 and 13.0 Bcf of gas as LNG in 2015 and 2014, respectively.
Hilcorp consolidated the operations and tariff for the four major gas pipelines in the Cook Inlet basin into the Kenai-Beluga Pipeline (KBPL) in 2014. On November 1, 2014, the RCA approved the consolidation. Prior to consolidation, gas transportation cost could make development of new gas fields cost prohibitive because the gas transport rates varied with flow and the number of pipelines the gas had to cross to transport gas. The consolidation provides gas producers a single rate for shipping gas on all of the four pipelines, which makes development of gas fields anywhere on the gas pipeline system more attractive to gas producers.
A project commenced by Alaska Gasline Development Corporation and affiliates of BP, ConocoPhillips, ExxonMobil and TransCanada (together, project participants) to construct a liquefaction facility, gas pipeline, and gas treatment plant is underway through a pre-filing process accepted by FERC. The mainline gas pipeline is expected to include off-take points to allow for the opportunity for future in-state deliveries of natural gas. The project participants are targeting to file a formal application with FERC in the fall of 2016. FERC authorizations for the project and commencement of construction are anticipated in the 2018-2019 timeframe, with operation in the 2024-2025 timeframe.
Cook Inlet Natural Gas Storage Alaska (CINGSA) began service April 1, 2012. The facility ensures local utilities, including Chugach, have gas available to meet deliverability requirements during peak periods and store gas during low demand periods. The RCA approved inception rates and a tariff for the CINGSA facility on January 31, 2011, and a Firm Storage Service (FSS) Agreement between the seller and Chugach in July of 2011. Injections into the facility began in 2012. Chugach's share of the capacity was 1.9 Bcf in 2015. Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day.
11
Recovery of Fuel and Purchased Power Costs
The RCA approved inclusion of all fuel and transportation costs related to our current contracts in the calculation of Chugach’s fuel and purchased power adjustment process which will ensure, in advance, that costs incurred under the contracts can be recovered from Chugach’s customers. The fuel and purchased power adjustment process collects under-recoveries and refunds over-recoveries from prior periods with minimal regulatory lag. Chugach's fuel and purchased power adjustment process includes quarterly filings with the RCA, which set the rates on projected costs, sales and system operations for the quarter. Any under- or over-recovery of costs is incorporated into the following quarterly filing. Chugach over-recovered $5.1 million and $1.5 million at December 31, 2015, and 2014, respectively. To the extent the regulated fuel and purchased power adjustment process does not provide for the timely recovery of costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.
Regulatory
Our base rates are approved by the RCA. Chugach filed its June 2014 Test Year General Rate Case on February 13, 2015, to reflect revenue and cost changes resulting from the expiration of MEA’s interim wholesale contract. On May 1, 2015, the proposed rates became effective on an interim and refundable basis for Chugach’s remaining customers. During January of 2016, Chugach reached a settlement with the Attorney General for the State of Alaska and filed the resulting stipulation with the RCA on January 21, 2016, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – June 2014 Test Year General Rate Case.”
To the extent the RCA does not allow for the recovery of our costs associated with our current or anticipated rate cases, Chugach could experience a material negative impact on its results of operations, financial position and cash flows.
Accounting Standards or Practices
We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.
Green House Gas Regulations, Carbon Emission and Climate Change
Uncertainty remains regarding the impacts of potential regulations regarding greenhouse gases (GHG), carbon emissions, and climate change on Chugach’s operations. The United States Environmental Protection Agency (EPA) is moving forward with regulations that seek to limit carbon emissions in the United States. Power plants are the single largest source of carbon emissions in the United States. On August 3, 2015, the EPA released the final 111(d) regulation aimed at reducing emissions of carbon dioxide (CO2) from existing power plants. Alaska is not bound by the 111(d) regulation, however 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. 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.
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Additional costs related to a GHG tax or cap and trade program, if enacted by Congress, or other regulatory action, could affect the relative cost of the energy Chugach produces. 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.
Other Environmental Regulations
Since January 1, 2007, transformer manufacturers have been required to meet the 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 are increasing from the original “TP1” levels to the new “DOE-2016” levels. The Energy Act mandates specific types of low voltage dry-type transformers manufactured and sold in the USA to have efficiencies as defined by the 10 CFR Part 431 standard when loaded to 35% of maximum capacity. Chugach is in the process of evaluating our transformer specifications and will make modifications as necessary with our alliance transformer manufacturers to ensure DOE-2016 is met. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.
Chugach is currently required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment. While we believe Chugach has obtained all material environmental-related approvals currently required to own and operate our facilities, Chugach may incur significant additional costs because of compliance with these requirements in addition to costs related to any costs of compliance with laws or regulations relating to GHG or carbon emissions. Failure to comply with environmental laws and regulations could have a material effect on Chugach, including potential civil or criminal liability and the imposition of fines or expenditures of funds to bring our facilities into compliance. Delay in obtaining, or failure to obtain and maintain in effect any environmental approvals, or the delay or failure to satisfy any applicable environmental regulatory requirements related to the operation of our existing facilities could result in significant additional costs to Chugach and a material adverse impact to Chugach’s results of operations, financial condition, and cash flows.
These factors, as well as weather, interest rates and economic conditions are largely beyond our control, but may have a material adverse effect on our earnings, cash flows and financial position.
Item 1B – Unresolved Staff Comments
None
13
General
During 2015, we had 602.7 MW of installed capacity consisting of 18 generating units at five power plants. These included 385.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 140.1 MW at SPP in Anchorage, which we jointly own with ML&P; 46.7 MW at IGT in Anchorage; and 19.2 MW at the Cooper Lake facility, which is on the Kenai Peninsula. We also own rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and ML&P. In April of 2015, Beluga Unit 8 was retired representing 53.0 MW of capacity. In August of 2015, IGT Unit 3 was retired representing 18.5 MW of capacity. Therefore, we had 531.2 MW of installed capacity consisting of 16 generating units at December 31, 2015.
In addition to our own generation, we purchased power from the 120 MW Bradley Lake Hydroelectric Project, which is owned by the Alaska Energy Authority (AEA), operated by HEA and dispatched by Chugach, and MEA’s newly constructed 171 MW EGS, which is also dispatched by Chugach. In 2015, we also purchased power from FIW.
The Beluga, IGT and SPP facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to IGT and SPP in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space).
Generation Assets
We own the land and improvements comprising our generating facilities at Beluga, IGT and SPP. Our principal generation assets are in two plants, Beluga and SPP. With SPP in operation, the Beluga units are occasionally used for peaking, but are primarily used as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with scheduled inspections and periodic upgrades. Beluga Unit 6 had a major inspection in 2010, in which many of the major components were replaced with new or refurbished parts, and since has had annual inspections through 2015. During the 2012 annual inspection, combustion components nearing end of life were also replaced. Beluga Unit 7 had a major inspection in 2012, in which many of the major components were replaced with new or refurbished parts, and since has had annual inspections through 2015. Beluga Unit 8, a steam turbine generator, also had a major inspection in 2012, and had annual inspections through 2014. In April of 2015, Beluga Unit 8 was retired.
On February 1, 2013, SPP began commercial operation, furnishing 200.2 MW of capacity provided by 4 generating units. Chugach owns and takes approximately 70% of this plant’s output and ML&P owns and takes the remaining 30%. Chugach proportionately accounts for its ownership in SPP. Our principal generation units at SPP are Units 10, 11, 12, and 13. Throughout 2015 and 2014, SPP units received preventative maintenance inspections consistent with original equipment manufacturer (OEM) recommendations. In each year, the gas turbine generators of Units 11, 12, and 13 received two internal combustion system inspections each and one full package inspection. The Unit 12 gas turbine was replaced with a new spare gas turbine. The removed gas turbine will be prepared for another full cycle of operation by the OEM and Chugach technicians, under our contractual service agreement. The turbine will then be staged at the power plant awaiting the next engine rotation. All three steam-generating boilers were internally inspected as well as hydrotested in accordance with OEM recommendations.
14
The Cooper Lake Hydroelectric Project is partially located on federal lands. Chugach operates and maintains the Cooper Lake project pursuant to a 50-year license granted to us by FERC in August of 2007. As part of the relicensing process, there was a negotiated Relicensing Settlement Agreement (RSA) entered into in August of 2005. A requirement of the RSA required Chugach to establish a flow regime in Cooper Creek below the Cooper Lake Dam. This project included a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works. The project was designed to replace colder water flowing into the Cooper Creek drainage with warmer Cooper Lake water. Project construction began in 2013 and was completed in July of 2015.
The two generating units at Cooper Lake, Units 1 and 2, have a combined capacity of 19.2 MW. Both units were taken out of service for annual maintenance in October of 2015 and 2014. The 2014 annual maintenance included generator testing and inspection by the OEM.
The Eklutna Hydroelectric Project is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October of 1997. The facility is jointly owned by Chugach (30%), MEA (17%) and ML&P (53%). The facility is operated by Chugach and maintained jointly by Chugach and ML&P. Chugach owns rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units.
15
The following matrix depicts nomenclature, run hours for 2015, percentages of contribution and other historical information for all Chugach generation units.
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Facility |
| Commercial Operation Date |
| Nomenclature |
| Rating |
| Run |
| Percent of Total Run Hours |
| Percent of Time Available |
Beluga Power Plant (3) | ||||||||||||
1 |
| 1968 |
| GE Frame 5 |
| 19.6 |
| 95.8 |
| 0.20 |
| 96.7 |
2 |
| 1968 |
| GE Frame 5 |
| 19.6 |
| 330.9 |
| 0.70 |
| 96.1 |
3 |
| 1973 |
| GE Frame 7 |
| 64.8 |
| 2,833.9 |
| 5.99 |
| 92.5 |
5 |
| 1975 |
| GE Frame 7 |
| 68.7 |
| 2,845.7 |
| 6.02 |
| 90.4 |
6 |
| 1976 |
| AP 11DM-EV |
| 79.2 |
| 252.5 |
| 0.53 |
| 72.8 |
7 |
| 1978 |
| AP 11DM-EV |
| 80.1 |
| 3,122.9 |
| 6.60 |
| 90.4 |
8 |
| 1981 |
| BBC DK021150 (2) |
| 53.0 |
| 1,938.3 |
| 4.10 |
| 25.3 |
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| 385.0 |
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Cooper Lake Hydroelectric Project | ||||||||||||
1 |
| 1960 |
| BBC MV 230/10 |
| 9.6 |
| 312.0 |
| 0.66 |
| 98.6 |
2 |
| 1960 |
| BBC MV 230/10 |
| 9.6 |
| 2,584.0 |
| 5.46 |
| 98.6 |
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| 19.2 |
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IGT Power Plant | ||||||||||||
1 |
| 1964 |
| GE Frame 5 |
| 14.1 |
| 12.9 |
| 0.03 |
| 57.6 |
2 |
| 1965 |
| GE Frame 5 |
| 14.1 |
| 55.8 |
| 0.12 |
| 91.8 |
3 |
| 1969 |
| Westinghouse 191G (8) |
| 18.5 |
| 27.0 |
| 0.06 |
| 58.1 |
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| 46.7 |
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Southcentral Power Project | ||||||||||||
10 |
| 2013 |
| Mitsubishi SC1F-29.5 (7) |
| 40.2 | (6) | 8,384.6 |
| 17.72 |
| 95.7 |
11 |
| 2013 |
| GE LM6000 PF |
| 33.3 | (6) | 8,069.3 |
| 17.06 |
| 93.1 |
12 |
| 2013 |
| GE LM6000 PF |
| 33.3 | (6) | 8,145.7 |
| 17.22 |
| 93.1 |
13 |
| 2013 |
| GE LM6000 PF |
| 33.3 | (6) | 8,290.9 |
| 17.53 |
| 95.3 |
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| 140.1 |
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Eklutna Hydroelectric Project | ||||||||||||
1 |
| 1955 |
| Newport News |
| 5.8 | (4) | N/A | (5) |
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| 94.4 |
2 |
| 1955 |
| Oerlikon custom |
| 5.9 | (4) | N/A | (5) |
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| 94.1 |
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| 11.7 |
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System Total |
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| 602.7 |
| 47,302.2 |
| 100.00 |
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(1) Capacity rating in MW at 30 degrees Fahrenheit. | ||||||||||||
(2) Steam-turbine powered generator with heat provided by exhaust from natural gas fueled Units 6 and 7 (combined-cycle). Beluga Unit 8 was retired in April of 2015. | ||||||||||||
(3) Beluga Unit 4 was retired during 1994. | ||||||||||||
(4) The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and ML&P. The capacity shown is our 30% share of the plant's output under normal operating conditions. The actual nameplate rating on each unit is 23.5 MW. | ||||||||||||
(5) Run hours are not recorded by Chugach for the Eklutna Hydroelectric Project as it is maintained by a committee of three owners. | ||||||||||||
(6) The Southcentral Power Project is jointly owned by Chugach and ML&P. The capacity shown is our 70% share of the plant's output under normal operating conditions. The actual nameplate rating for the project is 200.2 MW. | ||||||||||||
(7) Steam-turbine powered generator with heat provided by exhaust from natural gas fueled Units 11, 12 and 13 and additional heat from supplemental duct firing in the once through steam generators associated with the respective gas turbines (combined-cycle). | ||||||||||||
(8) IGT Unit 3 was retired in August of 2015.. | ||||||||||||
Note: BBC = Brown Boveri Corporation, AP = Alstom Power |
16
Transmission and Distribution Assets
As of December 31, 2015, our transmission and distribution assets included 42 substations and 407 miles of transmission lines, which included Chugach’s share of the Eklutna transmission line, 897 miles of overhead distribution lines and 809 miles of underground distribution line. We own the land on which 24 of our substations are located and a portion of the right-of-way connecting our Beluga plant to Anchorage. As part of our 1997 acquisition of 30% of the Eklutna Hydroelectric Project, we also acquired a partial interest in two substations and additional transmission facilities.
Most of Chugach’s generation sites and many of its substation sites are on Chugach-owned lands. The rights for the sites not on Chugach-owned lands are as follows: the Postmark and Point Woronzof Substations, and the East Terminal Site (N/S runway) are under rights from the State Department of Transportation and Public Facilities/Ted Stevens Anchorage International Airport; the East Terminal Site (6 mile) is under rights from the Matanuska-Susitna Borough; the West Terminal Site is under rights from the Army/Air Force; the University Substation is on State land under rights from the Federal Bureau of Land Management; the Hope and Daves Creek Substations are under rights from the State; the Portage Substation is under rights from the Alaska Railroad Corporation (ARRC); the Summit Lake Substation is on State land under rights from the United States Forest Service; the Dowling and Raspberry Substations are on Municipality of Anchorage land under rights from the State; and, the Indian Substation will be under rights from the Chugach State Park upon approval. The Cooper Lake Power Plant, Quartz Creek Substation, and the 69kV transmission line between them are operated under a federal license. Most of Chugach’s transmission, sub-transmission and distribution lines are either on public lands under rights from the federal, state, municipal, borough or ARRC, or on private lands via easements.
Title
On January 20, 2011, Chugach and the indenture trustee entered into the Indenture, granting a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt. 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.
17
Many of Chugach’s properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and by additional minor title encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.
Other Property
Bradley Lake. We are a participant in the Bradley Lake Hydroelectric Project, which is a 120 MW rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled below 90 MW to minimize losses and ensure system stability. We have a 30.4% (27.4 MW as currently operated) share in the Bradley Lake project’s output, and currently take Seward’s share which we net bill to them, for a total of 31.4% of the project’s capacity. We are obligated to pay 30.4% of the annual project costs regardless of project output.
The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166.0 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (ML&P, HEA and MEA (through AEG&T and AEEC), GVEA, Seward and us). The participating utilities have entered into take-or-pay power sales agreements under which AEA has sold percentage shares of the project capacity and the utilities 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). By contract, we also provide transmission and related services to all of the participants in the Bradley Lake project.
The term of our Bradley Lake power sales agreement is 50 years from the date of commercial operation of the facility (September of 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel and purchased power adjustment process. The share of Bradley Lake indebtedness for which we are responsible is approximately $21.6 million. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs and output pro rata, to the extent necessary to compensate for the failure of the defaulting 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 $5.7 million as a result of Chugach’s Bradley Lake take-or-pay obligations.
The State of Alaska provided an initial grant for work on a project to divert water from Battle Creek into Bradley Lake. The project is being managed by the Alaska Energy Authority. Diverting a portion of Battle Creek into Bradley Lake is currently estimated to increase annual energy output by 37,000 MWh. Chugach would be entitled to 30.4% of the additional energy produced.
18
Eklutna. Along with two other utilities, Chugach purchased the Eklutna Hydroelectric Project from the Federal Government in 1997. Ownership was transferred from the DOE’s Alaska Power Administration jointly to Chugach (30%), MEA (17%) and ML&P (53%). Through April 30, 2015, the power MEA purchased from the Eklutna Hydroelectric Project was pooled with Chugach’s purchases and sold back to MEA to be used to meet MEA’s overall power requirements.
Fuel Supply
In 2015, 86% of our power was generated from natural gas. Total gas purchased in 2015 was approximately 14 Bcf. In 2015, our sources of natural gas for firm sales were primarily divided among contracts with two major oil and gas companies. All of the production came from Cook Inlet, Alaska. ConocoPhillips under their current contract provided 62% of gas supplied for generation, while Hilcorp provided 32%. The current gas contract with ConocoPhillips began providing gas in 2010 and will expire December 31, 2016. The current gas contract with Hilcorp began providing gas in 2011 and will expire March 31, 2023. ConocoPhillips and Hilcorp, together, fill 100% of Chugach’s firm needs through March 31, 2023. Gas to provide economy energy sales to GVEA was supplied by a gas supply arrangement with Hilcorp through March of 2015.
ConocoPhillips
Chugach entered into a contract with ConocoPhillips in 2009, which started providing gas January 1, 2010, and will terminate December 31, 2016. The total amount of gas under the contract is currently estimated to be 60 Bcf.
The gas supplied by ConocoPhillips under the contract is separated into two volume tranches for pricing purposes. “Firm Fixed Quantity” gas meets a portion of Chugach’s base load requirements, while “Firm Variable Quantity” gas meets peaking needs. All of the gas purchased under the contract is now firm fixed since firm variable gas was not provided by the contract after December 31, 2013. The dividing line between firm fixed and firm variable volumes was calculated based on a methodology that involved using a multiplier and the simple average of Chugach’s average daily volumes for the 30 lowest volume days during the last calendar year. The ConocoPhillips contract during 2015 had a fixed volume delivery of 17,000 thousand cubic feet (Mcf) per day at the Firm Fixed Quantity price.
Pricing for firm fixed gas will be based on the average of five Lower 48 natural gas production areas. The contract price is calculated on a quarterly basis as the trailing average of the simple daily average of the Platts Gas Daily midpoint prices for each “flow day” in these market areas during the last quarter.
Hilcorp
Chugach entered into a contract with Marathon Alaska Production (MAP) in 2010, to provide gas beginning April 1, 2011, through December 31, 2014, which included two contract extension options that were exercised in 2011. Effective February 1, 2013, this contract was assigned to Hilcorp who purchased MAP’s assets in Cook Inlet. The total amount of gas under contract is currently estimated to be 40 Bcf. Pricing for the 2015 term of the Hilcorp contract was set at $7.13 per Mcf. Pricing for the 2016 term is $7.42 per Mcf.
19
On October 1, 2012, Chugach entered into a Gas Sales and Purchase Agreement with Hilcorp for the purchase of gas with an effective period of April 1, 2013, through March 31, 2015. This agreement was intended for Chugach to produce economy energy for GVEA. GVEA reimbursed Chugach for the cost of gas related to economy energy sales.
Cook Inlet Energy, LLC
Chugach entered into a Gas Sale and Purchase Agreement (GSPA) with CIE in 2013, to supply gas from April 1, 2014, through March 31, 2018, with an option to extend for an additional five years by mutual agreement during the term of the GSPA. The GSPA with CIE provides Chugach with an opportunity to diversify its gas supply portfolio, and minimize its current dependence on the gas agreements in place with two vendors. The gas that may be purchased under the GSPA with CIE is not required, however it introduces a new pricing mechanism.
The GSPA identifies and defines two types of gas purchases. Base Gas is defined by the volume of gas purchased on a firm or interruptible basis at an agreed delivery rate. Pricing for base gas purchases ranges from $6.12 to $7.31 per Mcf. Swing Gas is gas sold to Chugach at a delivery rate in excess of the applicable Base Gas agreed delivery rate. Pricing for swing gas purchases ranges from $7.65 to $9.14 per Mcf.
AIX Energy, LLC
Chugach entered into a contract with AIX Energy, LLC (AIX) in 2014, to supply gas from March 1, 2015, through February 29, 2016. This agreement caps the price of gas at $6.24 per Mcf and the total volume at 300,000 Mcf. In anticipation of this agreement’s expiration, Chugach entered into another gas sale and purchase agreement with AIX in November of 2015, to provide gas beginning April 1, 2016, through March 31, 2023, with the option to extend to March 31, 2029. The AIX agreements provide flexibility in both the purchase price and volumes and allow Chugach to further diversify its gas supply portfolio, with no minimum purchase requirements.
Natural Gas Transportation Contracts
The terms of the ConocoPhillips and Hilcorp agreements require Chugach to transport gas. Chugach took over the transportation obligation for natural gas shipments for gas supplied under its contracts on October 1, 2010. The following information summarizes the transportation obligations for Chugach:
ENSTAR (Alaska Pipeline Company)
ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our IGT Power Plant and SPP at a transportation rate of $0.6311 per Mcf. The agreement contains a fixed monthly customer charge of $2,600 for firm service.
Chugach and ENSTAR entered into a Firm Transportation Service Agreement on May 21, 2012, to provide for the transportation of gas to SPP. The agreement commenced on August 1, 2012, and remains in effect until canceled upon a 12-month written notice by either party. The agreement sets a contracted peak demand of 36,300 Mcf per day.
20
Harvest Alaska, LLC Pipeline System
Marathon Oil Company sold its share of its subsidiary pipeline company Marathon Pipe Line Company as part of a Cook Inlet asset divestiture effective February 1, 2013, to Hilcorp. Hilcorp now operates four major gas pipelines through Harvest Alaska, LLC, in the Cook Inlet basin, including the Kenai-Nikiski Pipeline (KNPL), the Beluga Pipeline (BPL), the Cook Inlet Gas Gathering System (CIGGS) and the Kenai-Kachemak Pipeline (KKPL). Chugach has entered into tariff agreements to ship gas on the KNPL, BPL and CIGGS. Effective August 1, 2013, Chugach entered into a special contract with KNPL for Firm Service capacity over the Kenai Pipeline Junction (KPL) compressor of 35,000 Mcf per month for the movement of gas to its Beluga power plant at a firm capacity rate of $2.13 per Mcf. This agreement ended effective October 31, 2014.
On November 1, 2014, the RCA approved consolidation of these four pipelines into a single pipeline, the KBPL. Chugach has entered into tariff agreements to ship gas on the KBPL.
Environmental Matters
Chugach’s operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase.
We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters.
Since January 1, 2007, transformer manufacturers have been required to meet the DOE efficiency levels as defined by the Energy Act for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels are increasing from the original “TP1” levels to the new “DOE-2016” levels. The Energy Act mandates specific types of low voltage dry-type transformers manufactured and sold in the USA to have efficiencies as defined by the 10 CFR Part 431 standard when loaded to 35% of maximum capacity. Chugach is in the process of evaluating our transformer specifications and will make modifications as necessary with our alliance transformer manufacturers to ensure DOE-2016 is met. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.
The Clean Air Act and 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 CO2 from existing power plants that provide electricity for utility customers. In the final rule, the EPA took the approach of making the individual states responsible for the development and implementation of plans to reduce the rate of CO2 emissions from the power sector. The EPA has 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
21
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. 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 new law or regulation, or limitation 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.
Chugach has certain litigation matters and pending claims that arise in the ordinary course of Chugach’s business. In the opinion of management, none of these other matters, individually, or in the aggregate, is or are likely to have a material adverse effect on Chugach’s results of operations, financial condition or cash flows.
Item 4 – Mine Safety Disclosures
Not Applicable
Item 5 – Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
Not Applicable
22
Item 6 – Selected Financial Data
The following table presents selected historical information relating to financial condition and results of operations for the years ended December 31:
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Balance Sheet Data | 2015 |
| 2014 |
| 2013 |
| 2012 |
| 2011 | |||||
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Electric plant, net: |
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In service | $ | 659,275,066 |
| $ | 657,899,592 |
| $ | 670,476,634 |
| $ | 442,515,434 |
| $ | 392,080,033 |
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Construction work in progress |
| 15,601,374 |
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| 21,567,341 |
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| 28,674,163 |
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| 263,459,794 |
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| 206,005,783 |
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Electric plant, net |
| 674,876,440 |
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| 679,466,933 |
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| 699,150,797 |
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| 705,975,228 |
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| 598,085,816 |
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Other assets |
| 113,118,571 |
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| 126,244,688 |
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| 139,033,241 |
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| 156,626,138 |
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| 254,843,842 |
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Total assets | $ | 787,995,011 |
| $ | 805,711,621 |
| $ | 838,184,038 |
| $ | 862,601,366 |
| $ | 852,929,658 |
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Capitalization: |
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Long-term debt |
| 448,908,517 |
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| 472,024,497 |
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| 496,914,274 |
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| 521,597,086 |
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| 296,090,108 |
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Equities and margins |
| 181,637,381 |
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| 176,925,299 |
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| 175,795,865 |
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| 166,764,373 |
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| 161,231,426 |
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Total capitalization | $ | 630,545,898 |
| $ | 648,949,796 |
| $ | 672,710,139 |
| $ | 688,361,459 |
| $ | 457,321,534 |
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Equity Ratio1 |
| 28.8% |
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| 27.3% |
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| 26.1% |
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| 24.2% |
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| 35.3% |
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Operations Data |
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Operating revenues | $ | 216,421,152 |
| $ | 281,318,513 |
| $ | 305,308,427 |
| $ | 266,971,468 |
| $ | 283,618,369 |
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Operating expenses |
| 188,791,558 |
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| 252,972,879 |
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| 278,738,497 |
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| 248,194,955 |
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| 262,341,866 |
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Interest expense |
| 22,194,290 |
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| 23,264,041 |
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| 24,691,582 |
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| 24,085,371 |
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| 18,681,680 |
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Capitalized interest |
| (379,845) |
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| (463,335) |
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| (1,310,110) |
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| (9,682,440) |
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| (1,934,703) |
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Net operating margins |
| 5,815,149 |
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| 5,544,928 |
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| 3,188,458 |
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| 4,373,582 |
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| 4,529,526 |
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Nonoperating margins |
| 687,703 |
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| 970,617 |
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| 7,355,585 |
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| 1,151,925 |
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| 1,043,736 |
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Assignable margins | $ | 6,502,852 |
| $ | 6,515,545 |
| $ | 10,544,043 |
| $ | 5,525,507 |
| $ | 5,573,262 |
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Margins for Interest Ratio2 | 1.29 |
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| 1.28 |
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| 1.43 |
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| 1.23 |
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| 1.30 |
1 Equity ratio equals equities and margins divided by the sum of our long-term debt and equities and margins.
2 Margins for interest ratio equals the sum of long and short-term interest expense and assignable margins divided by the sum of long and short-term interest expense, excluding amounts capitalized.
23
Item 7 – Management's Discussion and Analysis
of Financial Condition and Results of Operations
Caution Regarding Forward Looking Statements
Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained herein, except as required by law.
Results of Operations
Overview
Margins. We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to pay operating and maintenance costs, the cost of fuel and purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for reserves. These amounts are referred to as “margins.” Patronage capital, the retained margins of our members, constitutes our principal equity.
Times Interest Earned Ratio (TIER). Alaska electric cooperatives generally set their rates on the basis of TIER, which is a debt service coverage approach to ratemaking. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense (excluding capitalized interest). Chugach’s long-term interest expense for the years ended December 31, 2015, 2014 and 2013 was $21,811,573, $22,820,866, and $24,378,162, respectively. Chugach’s authorized TIER for ratemaking purposes on a system basis is 1.30, which was established by the RCA in order U-01-08(26) on January 31, 2003. The increase in 2013 was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant. The higher TIER in 2011 was due to certain debt classified as short-term, which was replaced with long-term debt in 2012.
Chugach’s achieved TIER includes nonoperating margins that are not generated by electric rates. We manage our business with a view towards achieving our authorized TIER (currently 1.30) averaged over a 5-year period. For further discussion on factors that contribute to TIER results, see “Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Year ended December 31, 2015, compared to the year ended December 31, 2014, and the year ended December 31, 2014 compared to the year ended December 31, 2013 – Expenses.” We achieved TIERs for the past five years as follows:
1 | 24 |
Year | TIER |
2015 | 1.30 |
2014 | 1.29 |
2013 | 1.43 |
2012 | 1.24 |
2011 | 1.58 |
24
Rate Regulation and Rates. Our electric rates are made up of two primary components: “base rates” and “fuel and purchased power rates.” Base rates provide recovery of fixed and variable costs (excluding fuel and purchased power) related to providing electric service. Fuel and purchased power rates provide recovery of fuel and purchased power costs.
The RCA approves both base rates and fuel and purchased power recovery rates paid by our retail and wholesale customers.
Base Rates. Chugach’s base rates, whether set under a general rate case or an SRF, are established to allow the continued recovery 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, other than fuel and purchased power, and those rates are then collected from our retail and wholesale customers. Under SRF, base rate increases are limited to 8% over a 12-month period and 20% over a 36-month period. Chugach is still permitted to submit general rate case filings while participating in the SRF process. However, during these periods, rate adjustments under SRF would temporarily cease. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis. Chugach resumed the SRF filing process, after receiving approval from the RCA, in the fourth quarter of 2010.
On May 1, 2015, base demand and energy rates increased approximately 22.0% to Chugach retail customers. Effective June 1, 2015, base demand and energy rates increased 16.9% to Seward. These changes were the result of Chugach’s June 2014 Test Year General Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – June 2014 Test Year General Rate Case.”
On January 3, 2014, base demand and energy rates increased 11.5% to Chugach retail customers. Effective February 1, 2014, base demand and energy rates increased 19.3% and 13.8% to MEA and Seward, respectively. These changes were the result of Chugach’s 2013 Test Year General Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2013 General Rate Case.”
On February 6, 2013, base demand and energy rates increased 26%, 40%, 35% and 20% to HEA, MEA, Seward and Chugach retail customers, respectively. These changes were the result of Chugach’s 2012 Test Year General Rate Case.
Fuel and Purchased Power Rates. We recover fuel and purchased power costs directly from our wholesale and retail customers through the fuel and purchased power rate adjustment process. Changes in fuel and purchased power costs are primarily due to fixed price or fuel price adjustment processes in our gas-supply contracts. Other factors, including generation unit availability also impact fuel and purchased power recovery rate levels. The fuel and purchased power adjustment is approved on a quarterly basis by the RCA. There are no limitations on the number or amount of fuel and purchased power recovery rate changes. Increases in our fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues. Therefore, revenue from the fuel and purchased power adjustment process does not impact margins. We recognize differences between projected recoverable fuel and purchased power costs and amounts actually recovered through rates. The fuel cost under/over recovery on our balance sheet represent the net accumulation of any under- or over-collection of fuel and purchased power costs. A fuel cost under-recovery will appear as an asset on our balance sheet and will be collected from our members in subsequent periods. Conversely, a fuel cost over-recovery will appear as a liability on our balance sheet and will be refunded to our members in subsequent periods.
25
Year ended December 31, 2015, compared to the year ended December 31, 2014, and the year ended December 31, 2014 compared to the year ended December 31, 2013
Margins
Our margins for the years ended December 31, were as follows:
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| 2015 |
| 2014 |
| 2013 | |||
Net Operating Margins | $ | 5,815,149 |
| $ | 5,544,928 |
| $ | 3,188,458 |
Nonoperating Margins | $ | 687,703 |
| $ | 970,617 |
| $ | 7,355,585 |
Assignable Margins | $ | 6,502,852 |
| $ | 6,515,545 |
| $ | 10,544,043 |
Net operating margins did not materially change in 2015 from 2014. The increase in net operating margins in 2014 from 2013 of $2.4 million, or 73.9%, was primarily due to a decrease in depreciation expense associated with Beluga Unit 8 assets, and a decrease in net interest, and was somewhat offset by a decrease in revenue.
Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other. The decrease in nonoperating margins in 2015 over 2014 was primarily due to lower interest income as a result of marketable securities sold in August of 2014. Nonoperating margins decreased in 2014 over 2013 primarily due by the recognition of the gain on the sale of the Bernice Lake Power Plant on December 31, 2013.
Revenues
Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2015, operating revenues were $64.9 million, or 23.1% lower than 2014. The decrease was primarily due to lower wholesale revenue caused by the expiration of the MEA wholesale contract, which was somewhat offset by higher rates charged to our remaining customers as a result of Chugach’s 2014 Test Year Rate Case. Lower economy energy sales, as a result of the expiration of the GVEA contract, also contributed to this decrease.
In 2014, operating revenues were $24.0 million, or 7.9% lower than 2013. The decrease was primarily due to lower wholesale revenue caused by the expiration of the HEA wholesale contract, which was somewhat offset by higher rates charged to both retail and wholesale customers as a result of Chugach’s 2013 Test Year Rate Case.
Retail revenue increased $7.8 million, or 4.8%, in 2015 from 2014. Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s June 2014 Test Year General Rate Case. Retail revenue increased $7.1 million, or 4.6%, in 2014 from 2013. Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s 2013 Test Year General Rate Case, which was somewhat offset by lower retail energy sales caused by warmer weather.
Wholesale revenue decreased $44.6 million, or 59.1%, in 2015 from 2014, primarily due to the expiration of MEA’s wholesale contract. Wholesale revenue decreased $32.5 million, or 30.1%, in 2014 from 2013, primarily due to the expiration of HEA’s wholesale contract.
26
Based on the results of fixed and variable cost recovery established in Chugach’s rate filings, wholesale sales to MEA contributed approximately $9.5 million, $26.2 million, and $22.8 million, for the years ended December 31, 2015, 2014 and 2013, respectively. Wholesale sales to Seward contributed approximately $1.3 million for the years ended December 31, 2015, and 2014 and $1.2 million for the year ended December 31, 2013. Wholesale sales to HEA contributed approximately $11.5 million for the year ended December 31, 2013.
The following table shows base rate sales revenue and fuel and purchased power revenue by customer class included in revenue for the years ended December 31, 2015, and 2014.
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| Base Rate Sales Revenue | Fuel and Purchased Power Revenue | Total Revenue | ||||||||||||||||||||||||
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| 2015 |
| 2014 |
| % Variance |
| 2015 |
| 2014 |
| % Variance |
| 2015 |
| 2014 |
| % Variance | |||||||||
Retail |
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Residential |
| $ | 61.1 |
| $ | 54.4 |
| 12.3 | % |
| $ | 24.8 |
| $ | 27.5 |
| (9.8 | %) |
| $ | 85.9 |
| $ | 81.9 |
| 4.9 | % |
Small Commercial |
| $ | 10.9 |
| $ | 9.6 |
| 13.5 | % |
| $ | 5.9 |
| $ | 6.4 |
| (7.8 | %) |
| $ | 16.8 |
| $ | 16.0 |
| 5.0 | % |
Large Commercial |
| $ | 41.7 |
| $ | 36.1 |
| 15.5 | % |
| $ | 24.0 |
| $ | 26.6 |
| (9.8 | %) |
| $ | 65.7 |
| $ | 62.7 |
| 4.8 | % |
Lighting |
| $ | 1.5 |
| $ | 1.5 |
| 0.0 | % |
| $ | 0.2 |
| $ | 0.2 |
| 0.0 | % |
| $ | 1.7 |
| $ | 1.7 |
| 0.0 | % |
Total Retail |
| $ | 115.2 |
| $ | 101.6 |
| 13.4 | % |
| $ | 54.9 |
| $ | 60.7 |
| (9.6 | %) |
| $ | 170.1 |
| $ | 162.3 |
| 4.8 | % |
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Wholesale |
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MEA |
| $ | 12.8 |
| $ | 34.6 |
| (63.0 | %) |
| $ | 13.4 |
| $ | 36.1 |
| (62.9 | %) |
| $ | 26.2 |
| $ | 70.7 |
| (62.9 | %) |
SES |
| $ | 2.0 |
| $ | 1.9 |
| 5.3 | % |
| $ | 2.7 |
| $ | 2.9 |
| (6.9 | %) |
| $ | 4.7 |
| $ | 4.8 |
| (2.1 | %) |
Total Wholesale |
| $ | 14.8 |
| $ | 36.5 |
| (59.5 | %) |
| $ | 16.1 |
| $ | 39.0 |
| (58.7 | %) |
| $ | 30.9 |
| $ | 75.5 |
| (59.1 | %) |
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Economy |
| $ | 0.9 |
| $ | 2.6 |
| (65.4 | %) |
| $ | 7.3 |
| $ | 34.3 |
| (78.7 | %) |
| $ | 8.2 |
| $ | 36.9 |
| (77.8 | %) |
Miscellaneous |
| $ | 2.2 |
| $ | 1.7 |
| 29.4 | % |
| $ | 5.0 |
| $ | 4.9 |
| 2.0 | % |
| $ | 7.2 |
| $ | 6.6 |
| 9.1 | % |
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Total Revenue |
| $ | 133.1 |
| $ | 142.4 |
| (6.5 | %) |
| $ | 83.3 |
| $ | 138.9 |
| (40.0 | %) |
| $ | 216.4 |
| $ | 281.3 |
| (23.1 | %) |
The following table shows the base rate sales revenue and fuel and purchased power revenue by customer class that is included in revenue for the years ended December 31, 2014, and 2013.
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| Base Rate Sales Revenue | Fuel and Purchased Power Revenue | Total Revenue | ||||||||||||||||||||||||
|
| 2014 |
| 2013 |
| % Variance |
| 2014 |
| 2013 |
| % Variance |
| 2014 |
| 2013 |
| % Variance | |||||||||
Retail |
|
|
|
|
|
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|
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|
|
|
|
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|
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|
|
Residential |
| $ | 54.4 |
| $ | 50.9 |
| 6.9 | % |
| $ | 27.5 |
| $ | 28.3 |
| (2.8 | %) |
| $ | 81.9 |
| $ | 79.2 |
| 3.4 | % |
Small Commercial |
| $ | 9.6 |
| $ | 8.8 |
| 9.1 | % |
| $ | 6.4 |
| $ | 6.5 |
| (1.5 | %) |
| $ | 16.0 |
| $ | 15.3 |
| 4.6 | % |
Large Commercial |
| $ | 36.1 |
| $ | 32.5 |
| 11.1 | % |
| $ | 26.6 |
| $ | 26.6 |
| 0.0 | % |
| $ | 62.7 |
| $ | 59.1 |
| 6.1 | % |
Lighting |
| $ | 1.5 |
| $ | 1.4 |
| 7.1 | % |
| $ | 0.2 |
| $ | 0.2 |
| 0.0 | % |
| $ | 1.7 |
| $ | 1.6 |
| 0.0 | % |
Total Retail |
| $ | 101.6 |
| $ | 93.6 |
| 8.5 | % |
| $ | 60.7 |
| $ | 61.6 |
| (1.5 | %) |
| $ | 162.3 |
| $ | 155.2 |
| 4.6 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEA |
| $ | 0.0 |
| $ | 15.5 |
| (100.0 | %) |
| $ | 0.0 |
| $ | 22.3 |
| (100.0 | %) |
| $ | 0.0 |
| $ | 37.8 |
| (100.0 | %) |
MEA |
| $ | 34.6 |
| $ | 28.4 |
| 21.8 | % |
| $ | 36.1 |
| $ | 37.0 |
| (2.4 | %) |
| $ | 70.7 |
| $ | 65.4 |
| 8.1 | % |
SES |
| $ | 1.9 |
| $ | 1.7 |
| 11.8 | % |
| $ | 2.9 |
| $ | 3.1 |
| (6.5 | %) |
| $ | 4.8 |
| $ | 4.8 |
| 0.0 | % |
Total Wholesale |
| $ | 36.5 |
| $ | 45.6 |
| (20.0 | %) |
| $ | 39.0 |
| $ | 62.4 |
| (37.5 | %) |
| $ | 75.5 |
| $ | 108.0 |
| (30.1 | %) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Economy |
| $ | 2.6 |
| $ | 2.7 |
| (3.7 | %) |
| $ | 34.3 |
| $ | 35.1 |
| (2.3 | %) |
| $ | 36.9 |
| $ | 37.8 |
| (2.4 | %) |
Miscellaneous |
| $ | 1.7 |
| $ | 2.0 |
| (15.0 | %) |
| $ | 4.9 |
| $ | 2.3 |
| 113.0 | % |
| $ | 6.6 |
| $ | 4.3 |
| 53.5 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue |
| $ | 142.4 |
| $ | 143.9 |
| (1.0 | %) |
| $ | 138.9 |
| $ | 161.4 |
| (13.9 | %) |
| $ | 281.3 |
| $ | 305.3 |
| (7.9 | %) |
27
The major components of our operating revenue for the years ending December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2015 |
| 2014 |
| 2014 |
| 2013 |
| 2013 | |||
| Sales (MWh) |
| Revenue |
| Sales (MWh) |
| Revenue |
| Sales (MWh) |
| Revenue | |||
Retail | 1,133,427 |
| $ | 170,147,462 |
| 1,134,527 |
| $ | 162,334,941 |
| 1,162,364 |
| $ | 155,208,714 |
Wholesale: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HEA | 0 |
|
| 0 |
| 0 |
|
| 0 |
| 463,582 |
|
| 37,788,679 |
MEA | 275,362 |
|
| 26,177,627 |
| 764,025 |
|
| 70,694,965 |
| 773,836 |
|
| 65,352,294 |
Seward | 61,347 |
|
| 4,770,129 |
| 61,499 |
|
| 4,833,205 |
| 64,507 |
|
| 4,830,063 |
Total Wholesale | 336,709 |
|
| 30,947,756 |
| 825,524 |
|
| 75,528,170 |
| 1,301,925 |
|
| 107,971,036 |
Economy energy | 105,815 |
|
| 8,150,983 |
| 358,988 |
|
| 36,896,019 |
| 351,390 |
|
| 37,764,494 |
Other | N/A |
|
| 7,174,951 |
| N/A |
|
| 6,559,383 |
| N/A |
|
| 4,364,183 |
Total | 1,575,951 |
| $ | 216,421,152 |
| 2,319,039 |
| $ | 281,318,513 |
| 2,815,679 |
| $ | 305,308,427 |
Since 1989, we have sold economy (non-firm) energy to GVEA, which uses that energy to serve its own loads. On April 6, 2010, Chugach and GVEA finalized an agreement for Chugach to provide a minimum of 20 MW of economy energy to GVEA on a non-firm basis based on an interruptible gas supply arrangement, which Chugach entered into with UNOCAL to supply gas for economy energy sales to GVEA. The agreement commenced on May 1, 2010, and was due to continue through March 31, 2013, however, on October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy sales through March of 2015. Sales were be made under the terms and conditions of Chugach’s economy energy sales tariff approved by the RCA. The price to GVEA included the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin. Chugach also entered into gas supply arrangements for GVEA economy energy sales.
In 2015, 2014, and 2013, economy sales to GVEA constituted approximately 4%, 13%, and 12%, respectively, of our sales revenues. Economy energy revenue decreased in 2015 from 2014 due to the expiration of the contract with GVEA at the end of the first quarter of 2015. Economy energy revenue did not materially change in 2014 from 2013.
Expenses
The major components of our operating expenses for the years ended December 31 were as follows:
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 |
| 2013 | |||
Fuel | $ | 66,534,877 |
| $ | 126,038,350 |
| $ | 136,610,262 |
Power production |
| 16,886,257 |
|
| 21,082,176 |
|
| 21,911,324 |
Purchased power |
| 19,599,994 |
|
| 15,608,396 |
|
| 27,836,680 |
Transmission |
| 6,287,558 |
|
| 6,138,658 |
|
| 6,624,836 |
Distribution |
| 14,089,862 |
|
| 13,002,157 |
|
| 13,225,242 |
Consumer accounts |
| 6,117,625 |
|
| 5,887,713 |
|
| 6,014,888 |
Administrative, general and other |
| 23,623,299 |
|
| 25,036,248 |
|
| 23,131,149 |
Depreciation |
| 35,652,086 |
|
| 40,179,181 |
|
| 43,384,116 |
Total operating expenses | $ | 188,791,558 |
| $ | 252,972,879 |
| $ | 278,738,497 |
28
Fuel
Chugach recognizes actual fuel expense as incurred. Fuel expense decreased $59.5 million, or 47.2%, in 2015 from 2014. The decrease was primarily due to a decrease in the natural gas used, as a result of the expiration of MEA’s wholesale contract and GVEA’s economy energy contract, lower transportation costs, and a decrease in the average effective delivered price. In 2015, Chugach used 13,058,423 Mcf of fuel at an average effective delivered price of $4.69 per Mcf. Fuel expense decreased $10.6 million, or 7.7%, in 2014 from 2013. The decrease was primarily due to a decrease in the natural gas used, primarily due to the expiration of HEA’s wholesale contract, and lower transportation costs which was somewhat offset by an increase in the average effective delivered price. In 2014, Chugach used 20,216,736 Mcf of fuel at an average effective delivered price of $5.95 per Mcf.
Power Production
Power production expense decreased $4.2 million, or 19.9%, in 2015 from 2014, primarily due to a decrease in operating and maintenance costs at Beluga, as a result of the retirement of Beluga Unit 8 during the second quarter of 2015. Power production expense did not materially change in 2014 from 2013.
Purchased Power
Purchased power expense increased $4.0 million, or 25.6%, in 2015 from 2014, primarily due to purchases associated with MEA’s EGS and a higher average effective price. In 2015, Chugach purchased 295,925 MWh of energy at an average effective price of 5.68 cents per kWh. Purchased power expense decreased $12.2 million, or 43.9%, in 2014 from 2013, primarily due to less energy purchased caused by a decrease in purchase requirements as a result of the expiration of HEA’s wholesale contract, which was somewhat offset by an increase in the average effective price. In 2014, Chugach purchased 240,887 MWh of energy at an average effective price of 5.38 cents per kWh.
Transmission
Transmission expense did not materially change in 2015 from 2014. Transmission expense decreased $0.5 million, or 7.3%, in 2014 from 2013, primarily due to less substation and overhead line maintenance, as well as the expiration of leases associated with HEA��s wholesale and other related contracts.
Distribution
Distribution expense increased $1.1 million, or 8.4%, in 2015 from 2014, primarily due to the transfer of costs associated with storm damages to a deferred project in 2014. Distribution expense did not materially change in 2014 from 2013.
Consumer Accounts
Consumer Accounts expense did not materially change in 2015 from 2014 or in 2014 from 2013.
29
Administrative, General and Other Expense
Administrative, general and other expense decreased $1.4 million, or 5.6%, in 2015 from 2014, primarily due to a reduction in workers’ compensation and costs associated with preliminary survey and investigation charges of projects. Administrative, general and other expense increased $1.9 million, or 8.2%, in 2014 from 2013, primarily due to accrued workers’ compensation, higher labor expense and costs associated with project studies.
Depreciation
Depreciation and amortization expense decreased $4.5 million, or 11.3%, in 2015 from 2014, primarily due to the retirement of Beluga Unit 8 assets during the first quarter of 2015, as well as a change in depreciation rates associated with the use of Beluga’s remaining units from base load to peaking units, coinciding with the expiration of MEA’s interim wholesale contract. Depreciation and amortization expense decreased $3.2 million, or 7.4%, in 2014 from 2013, primarily due to depreciation associated with Beluga Unit 8 assets.
Interest
Interest on long-term debt and other decreased $1.1 million, or 4.6%, in 2015 from 2014 and $1.4 million, or 5.8%, in 2014 from 2013, reflecting the principal payments made on long-term debt.
Interest charged to construction did not materially change in 2015 from 2014. Interest charged to construction decreased $0.8 million, or 64.6%, in 2014 from 2013 primarily due to a decrease in the average construction work in progress (CWIP) balance caused by the timing of commercial operation of SPP in 2013.
Patronage Capital (Equity)
The following table summarizes our patronage capital and total equity position for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 |
| 2013 | |||
Patronage capital at beginning of year |
| $ | 164,135,053 |
| $ | 162,749,889 |
| $ | 153,832,674 |
Retirement/net transfer of capital credits |
|
| (3,190,124) |
|
| (5,130,381) |
|
| (1,626,828) |
Assignable margins |
|
| 6,502,852 |
|
| 6,515,545 |
|
| 10,544,043 |
Patronage capital at end of year |
|
| 167,447,781 |
|
| 164,135,053 |
|
| 162,749,889 |
Other equity1 |
|
| 14,189,600 |
|
| 12,790,246 |
|
| 13,045,976 |
Total equity at end of year |
| $ | 181,637,381 |
| $ | 176,925,299 |
| $ | 175,795,865 |
|
|
|
|
|
|
|
|
|
|
1 Other equity includes memberships and donated capital on capital credit retirements. |
We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board. We currently have a practice of retiring patronage capital on a first-in, first-
30
out basis for retail customers. The Board may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002.
Capital credits retired were $3,190,124 and $5,130,381 for the years ended December 31, 2015, and 2014, respectively. Net of HEA’s allocations, capital credits retired were $1,626,828 for the years ended December 31, 2013.
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 liabilities and equities and margins.
Changes in Financial Condition
Assets
Total assets decreased $17.7 million, or 2.2%, in 2015 from 2014, primarily due to decreases in net utility plant, accounts receivable, fuel stock and deferred charges. Net utility plant decreased $4.6 million, or 0.7%, caused by depreciation expense in excess of extension and replacement of plant. Accounts receivable decreased $7.8 million, or 21.7%, in 2015 over 2014 primarily due to the expiration of the MEA and GVEA contracts. Fuel stock decreased $2.6 million, or 26.8%, in 2015 from 2014, primarily due to the use of fuel from the fuel storage facility. Deferred charges decreased $1.9 million, or 8.8%, primarily due to annual amortization and recovery of such costs from customers.
Liabilities and Equity
Total liabilities, equities and margins decreased $17.7 million, or 2.2%, in 2015 from 2014. Decreases in long term obligations and fuel payable were somewhat offset by increases in total equities and margins, fuel cost over-recovery, other liabilities, and cost of removal obligation. Long term obligations decreased $24.1 million, or 5.1%, caused by principal payments on Chugach’s bonds and fuel payable decreased $6.2 million, or 55.6%, as a result of less fuel purchased. Total equities and margins increased $4.7 million, or 2.7%, primarily due to the margins generated in 2015. Fuel cost over-recovery increased $3.7 million, or 251.3%, due to the over-recovery of the prior quarter’s fuel and purchased power costs. Other liabilities increased $3.5 million, or 75.8%, primarily due to an increase in the payables associated with the underground ordinance and 2015 capital credit retirement. Cost of removal obligation increased $1.4 million, or 2.7%, as a result of annual removal costs of electric plant in service included in depreciation rates.
Inflation
Chugach is subject to the inflationary trends existing in the general economy. We do not believe that inflation had a significant effect on our operations in 2015. One of Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel recovery process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.
31
Contractual Obligations and Commercial Commitments
The following are Chugach’s contractual and commercial commitments as of December 31, 2015:
Contractual cash obligations – Payments Due By Period
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|
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|
|
|
|
|
|
(In thousands) | Total |
| 2016 |
| 2017-2018 |
| 2019-2020 |
| Thereafter | |||||
Long-term debt, including current portion | $ | 473,024 |
| $ | 24,116 |
| $ | 48,994 |
| $ | 50,172 |
| $ | 349,742 |
Long-term interest expense1 |
| 250,172 |
|
| 20,588 |
|
| 36,907 |
|
| 32,760 |
|
| 159,917 |
Commercial Paper2 |
| 20,000 |
|
| 20,000 |
|
| 0 |
|
| 0 |
|
| 0 |
Bradley Lake3 |
| 25,911 |
|
| 3,716 |
|
| 7,409 |
|
| 7,602 |
|
| 7,184 |
Fuel and fuel transportation expense4 |
| 388,927 |
|
| 51,033 |
|
| 129,916 |
|
| 97,787 |
|
| 110,191 |
Capital Credit Retirements5 |
| 7,931 |
|
| 0 |
|
| 7,931 |
|
| 0 |
|
| 0 |
Total | $ | 1,165,965 |
| $ | 119,453 |
| $ | 231,157 |
| $ | 188,321 |
| $ | 627,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Long-term interest expense includes fixed and variable rates. Variable rates are based on rates at December 31, 2015, for years 2016-2020 and thereafter, see "Item 8 - Financial Statements and Supplementary Data - Note 11 - Debt." | ||||||||||||||
2 At December 31, 2015, Chugach's Commercial Paper Program was backed by a $100.0 million Unsecured Credit Agreement, which funds capital requirements. At December 31, 2015, there was $20.0 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $80.0 million and could be used for future operational and capital funding requirements. | ||||||||||||||
3 Estimated annual debt service requirements | ||||||||||||||
4 Estimated committed fuel and fuel transportation expense | ||||||||||||||
5 Capital credit retirement commitments |
Purchase obligations
Chugach is a participant and has a 30.4% share in the Bradley Lake Hydroelectric Project, see “Item 2 – Properties – Other Property – Bradley Lake.” This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, Chugach’s share of which has averaged $4.9 million over the past five years. We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs.
Our primary sources of natural gas are ConocoPhillips and Hilcorp, see “Item 2 – Properties – Fuel Supply.” Our fuel costs vary due to the impact of the indices used to index the price of our ConocoPhillips contract and is inherently difficult to predict. We pass fuel costs directly to our wholesale and retail customers through the fuel recovery process, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Overview – Rate Regulation and Rates – Fuel and Purchased Power Recovery.”
32
Liquidity and Capital Resources
We ended 2015 with $15.6 million of cash and cash equivalents, down from $16.4 at December 31, 2014 and up from $4.3 million at December 31, 2013. Cash equivalents consist of all highly liquid debt instruments with a maturity of three months or less when purchased, an Overnight Repurchase Agreement and Concentration account with First National Bank Alaska (FNBA) and a money market account with UBS Financial Services.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 |
| 2013 | |||
Total cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities | $ | 52,096,436 |
| $ | 58,766,300 |
| $ | 36,982,973 |
Investing activities |
| (32,347,745) |
|
| (12,687,167) |
|
| (44,046,875) |
Financing activities |
| (20,486,734) |
|
| (34,061,334) |
|
| (2,636,404) |
|
|
|
|
|
|
|
|
|
Increase/(Decrease) in cash and cash equivalents | $ | (738,043) |
| $ | 12,017,799 |
| $ | (9,700,306) |
Cash provided by operating activities was $52.1 million in 2015 compared to $58.8 million in 2014 and $37.0 million in 2013. The decrease in cash provided by operating activities in 2015 from 2014 was primarily due to the expiration of the MEA and GVEA contracts in 2015, exclusive of fuel and purchased power revenue and expense, as well as more cash used for fuel. These were somewhat offset by an increase in cash provided by the over-collection of fuel and purchased power costs recovered through the fuel and purchased power adjustment process in 2015 from 2014. Cash provided by operating activities increased in 2014 from 2013 primarily due to the over-collection of fuel and purchased power costs recovered through the fuel and purchased power adjustment process, as well as less cash used for fuel stock due to the use of fuel storage, and less cash used for fuel primarily due to the timing of payments and the difference in price and quantity of fuel purchased as a result of the expiration of HEA’s contract. Cash provided by accounts receivable increased in 2014 from 2013 primarily due to amounts outstanding for wholesale energy sales to HEA, economy energy sales to GVEA, and SPP costs billed to ML&P.
Cash used in investing activities was $32.3 million in 2015 compared to $12.7 million in 2014 and $44.0 million in 2013. The change in cash used in investing activities in 2015 from 2014 and in 2014 from 2013 was primarily due to the impact of proceeds for capital grants and our investment activity with marketable securities in 2014.
Cash used in financing activities was $20.5 million in 2015 compared to $34.1 million in 2014 and $2.6 million in 2013. The change in cash used in financing activities in 2015 from 2014 and in 2014 from 2013 was primarily due to a decrease in the average commercial paper balance and Chugach’s capital credit retirement in 2014.
33
Sources of Liquidity
Chugach has satisfied its operational and capital cash requirements through internally generated funds, a $50.0 million line of credit from NRUCFC and a $100.0 million Commercial Paper Program. At December 31, 2015, there was no outstanding balance on our NRUCFC line of credit and $20.0 million of outstanding commercial paper under the Commercial Paper Program. Thus, at December 31, 2015, our available borrowing capacity under our line of credit was $50.0 million and our available commercial paper capacity was $80.0 million. The NRUCFC line of credit expires October 12, 2017.
On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper Program. Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million as the requirement for short-term borrowing has decreased and on June 29, 2012, amended and extended the Credit Agreement. Information concerning our Commercial Paper Program and the 2010 Credit Agreement are described in Note 11 to the financial statements, see “Item 8 -Financial Statements and Supplementary Data- Note 11 – Debt – Commercial Paper.”
A table providing information regarding monthly average commercial paper balances outstanding and corresponding weighted average interest rates are described in Note 11 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt – Commercial Paper.”
Chugach has a term loan facility with CoBank. Loans made under this facility are evidenced by the 2011 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated January 19, 2011, and secured by the Indenture. At December 31, 2015, Chugach had $24.9 million outstanding with CoBank.
Under the Indenture, additional obligations may be sold by Chugach upon the basis of bondable additions and the retirement or defeasance of or principal payments on previously outstanding obligations. The beginning balance of bondable additions on January 20, 2011, was $322.2 million, which would support the issuance of additional debt of approximately $293.0 million. On March 15, 2011, Chugach used $5.5 million of bondable additions to pay financing costs associated with the 2011 Series A Bond transaction. On January 11, 2012, Chugach used $275.0 million of bondable additions when it issued $250.0 million of 2012 Series A Bonds. The balance of bondable additions after the January 11, 2012, transaction was $38.2 million. On October 9, 2015, Chugach certified bondable additions of $261.9 million. The balance of bondable additions is now $300.1 million, which would support the issuance of approximately $272.9 million in additional debt. Chugach’s bondable additions balance is a reflection of its beginning balance less property retirements. Chugach’s ability to sell debt obligations will be dependent on the market’s perception of Chugach’s financial condition and credit rating, and Chugach’s continuing compliance with the financial covenants, including the rate covenant, contained in the Indenture and its other credit documents. No assurance can be given that Chugach will be able to sell additional debt obligations even if otherwise permitted under the Indenture.
34
Financing
Information concerning our Financings are described in Note 11 to the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 11 – Debt – Financing.”
Principal maturities of our outstanding long-term indebtedness at December 31, 2015, are set forth below:
|
|
|
|
Year Ending December 31 |
| Principal Maturities | |
2016 |
| $ | 24,115,980 |
2017 |
|
| 24,362,621 |
2018 |
|
| 24,631,934 |
2019 |
|
| 24,925,809 |
2020 |
|
| 25,246,476 |
Thereafter |
|
| 349,741,677 |
|
| $ | 473,024,497 |
During 2015, we spent approximately $35.1 million on capital-construction projects, net of reimbursements, which includes interest capitalized during construction. We develop five-year capital improvement plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through the five-year Capital Improvement Plan (CIP).
Set forth below is an estimate of internal funding for capital expenditures for the years 2016 through 2020 as contained in the CIP, which was approved by the Board on November 18, 2015:
|
|
Year | Estimated Expenditures |
2016 | $23.7 million |
2017 | $17.6 million |
2018 | $16.1 million |
2019 | $18.1 million |
2020 | $15.1 million |
We expect that cash flows from operations and external funding sources, including our available line of credit and Commercial Paper Program, will be sufficient to cover future operational and capital funding requirements.
Chugach Operations
In the near term, Chugach continues to face the challenges of operating in a flat load growth environment and securing replacement revenue sources. These challenges, along with energy issues and plans at the state level, will shape how Chugach proceeds into the future.
Prior to the expiration of MEA’s wholesale power contract with Chugach at the end of 2014, Chugach entered into an Interim Power Sales Agreement with MEA to provide all demand and energy requirements on a firm basis on existing tariffs for a minimum one quarter period beginning January 1, 2015, and ending on March 31, 2015, while MEA completed construction of its new power plant, the EGS. On March 31, 2015, Chugach entered into a MOU with MEA to extend the Interim Power Sales Agreement for one month while MEA continued to prepare its EGS and SCADA system for commercial operation. This MOU also delayed the implementation
35
of the Dispatch Services Agreement with MEA to provide electric and natural gas dispatch services to EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for Eklutna Hydroelectric Project to May 1, 2015. On April 30, 2015, the Interim Power Sales Agreement with MEA expired.
Chugach had been preparing for the expiration of its second wholesale power contract for some time and has taken steps to reduce costs in order to mitigate the rate impacts to its remaining customers. Despite the loss of these two wholesale power contracts which accounted for approximately 50% of energy sales and 40% of sales revenue, the net system rate increase for Chugach’s remaining customers was approximately 20%. Chugach’s 10-year financial forecast results indicate it can sustain operations and meet financial covenants without these wholesale contracts. In addition, because Chugach’s rates are established by the RCA, Chugach expects to maintain its ability to recover Chugach’s specific costs of providing service despite the loss of these customers.
Chugach is also pursuing replacement sources of revenue through potential new power sales and dispatch agreements, as well as transmission wheeling and ancillary services tariff revisions. Chugach has updated and expanded its operating tariff to include both firm and non-firm transmission wheeling services and attendant ancillary services in support of third-party transactions on the Chugach system. Chugach believes that cost reduction and containment, successful implementation of new power sales and dispatch agreements and revised tariffs will mitigate additional rate increases. However, Chugach cannot assure that it will be able to replace sources of revenue or that any replacement of revenue sources, revised tariffs or cost reduction and containment measures will fully offset any rate increases in this timeframe.
Railbelt Grid Unification
Chugach is focused on efforts in the Railbelt to explore the benefits of grid unification. Currently, each of the six electric utilities in the Railbelt own a portion of the transmission grid, as does the AEA. Chugach is a proponent of following other successful business models to effectively unify the grid. Discussions on the issue led the Alaska State Legislature in 2014 to appropriate $250,000 to the RCA to explore the issue and report back to legislators. The RCA expects to analyze and review present efforts in order to assess the organizational and governance structure needed for an independent consolidated system operator, see “Item 8 - Financial Statements and Supplementary Data - Note 5 – Regulatory Matters - Operation and Regulation of the Alaska Railbelt Transmission System.” Progress reports associated with system-wide economic dispatch are required beginning in 2016. 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. Chugach intends to finalize this review and evaluation in the first or second quarter of 2016. While Chugach cannot determine the materiality of any effect on its results of operations, financial condition, and cash flows until a business model and plan are adopted, it anticipates a positive outcome.
36
Fuel Supply
Chugach actively manages its fuel supply needs and currently has contracts in place to meet up to 100% of its anticipated needs through March of 2023. Chugach continues its efforts to secure long-term reliable gas supply solutions and encourage new development and continued investment in Cook Inlet. The State of Alaska’s DNR published a study in September of 2015, “Updated Engineering Evaluation of Remaining Cook Inlet Gas Reserves,” to provide an estimate of Cook Inlet’s gas supply. The study estimated there are 1,183 Bcf of proved and probable reserves remaining in Cook Inlet’s legacy fields. This is higher than the 2009 DNR study estimate of 1,142 Bcf. Effectively, Cook Inlet gas supply has slightly increased from 2009. The 2015 DNR estimate does not include reserves from a large gas field under development by Furie Operating Alaska, LLC (Furie) and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has begun production. The platform and other production facilities are designed for up to 200 MMcf per day. Other gas producers are actively developing gas supplies in the Cook Inlet. Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.
Renewable Energy Goals
A State of Alaska Energy Policy approved by the legislature in 2010 included legislative intent that the state achieve a 15% increase in energy efficiency on a per capita basis between 2010 and 2020, receive 50% of its electric generation from renewable and alternative energy sources by 2025, work to ensure reliable in-state gas supply for residents of the state, and that the state power project fund serve as the main source of state assistance for energy projects, remain a leader in petroleum and natural gas production and become a leader in renewable and alternative energy development.
The main project moving Alaska toward its renewable energy goals is the Susitna-Watana Hydroelectric Project which is currently planned to be located on the Susitna River, approximately halfway between Anchorage and Fairbanks. The State of Alaska began appropriating funds to the AEA for this project in the state’s 2012 fiscal year budget, totaling approximately $180.7 million through the spring of 2014. However, on December 26, 2014, the Governor of the State of Alaska (Governor) issued an Administrative Order suspending discretionary spending on a number of capital projects, including this project, due to the large state budget deficit. In July of 2015, the Governor approved using $6.6 million in uncommitted funds from a prior Susitna-Watana appropriation to continue moving the project forward. In October of 2015, the state’s Office of Management and Budget lifted the spending freeze on the Susitna-Watana Hydroelectric Project providing AEA with access to funds representing approximately three percent of the total allocation to the current project proposal to date. AEA estimates the project’s cost at over $5.5 billion and plans to act based on the funding the state’s fiscal reality allows. AEA continued the pre-licensing study process with the FERC and filed Part D of the Initial Study Report on November 6, 2015. On December 2, 2015, the FERC published an updated licensing schedule, including stakeholder meetings set to begin in March of 2016. Chugach has been working with and will continue to work with AEA and other parties on this effort.
37
Appropriations
The 2015 fiscal year State of Alaska capital budget contained $3.5 million in appropriations for Chugach’s Stetson Creek Diversion project. The 2014 fiscal year State of Alaska capital budget contained $287.5 thousand in appropriations for Chugach. Funding for these projects flowed through either the AEA or the Municipality of Anchorage.
Off-Balance Sheet Arrangements
We have not created, and are not party to, any special-purpose or off-balance-sheet entities for the purpose of raising capital, incurring debt or operating parts of our business that are not consolidated into our financial statements. We do not have any arrangements or relationships with entities that are not consolidated into our financial statements that are reasonably likely to materially affect our liquidity or the availability of our capital resources.
Critical Accounting Policies
Our accounting and reporting policies comply with United States generally accepted accounting principles (GAAP). The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and reported amounts of assets and liabilities in the financial statements. Significant accounting policies are described in Note 2 to the financial statements, see “Item 8 –Financial Statements and Supplementary Data – Significant Accounting Policies.” Critical accounting policies are those policies that management believes are the most important to the portrayal of Chugach's financial condition and results of its operations, and require management's most difficult, subjective, or complex judgments, often as a result of the need to make estimates about matters that are inherently uncertain. Most accounting policies are not considered by management to be critical accounting policies. Several factors are considered in determining whether or not a policy is critical in the preparation of financial statements. These factors include, among other things, whether the estimates are significant to the financial statements, the nature of the estimates, the ability to readily validate the estimates with other information including third parties or available prices, and sensitivity of the estimates to changes in economic conditions and whether alternative accounting methods may be utilized under GAAP. For all of these policies management cautions that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment. Management has discussed the development and the selection of critical accounting policies with Chugach's Audit and Finance Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2015.
Electric Utility Regulation
Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on our specific allowable costs. As a result, Chugach applies FASB ASC 980, “Topic 980 – Regulated Operations.” Through the ratemaking process, the regulators may require the recognition of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of regulatory liabilities. The application of FASB ASC 980 has a further effect on Chugach's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by
38
Chugach; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach's results of operations than they would on a non-regulated company. As reflected in the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 2j – Deferred Charges and Credits,” significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.
Unbilled revenue
Chugach calculates unbilled retail revenue at the end of each month to ensure the recognition of a full month’s revenue. Chugach estimates calendar-month unbilled sales based on the relationship between current retail customer consumption and actual daily substation deliveries. Sales equate to total energy delivered to substations, which accounts for total energy production, less losses. Calendar unbilled revenue is determined by multiplying estimated unbilled kWh sales by respective billing class determinants to produce an estimate of calendar month revenue. Chugach accrued $10,531,377 and $9,885,526 of unbilled retail revenue at December 31, 2015 and 2014, respectively.
New Accounting Standards
Information concerning New Accounting Standards are described in Note 3 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data – Note 3 – Recent Accounting Pronouncements.”
39
Item 7A – Quantitative and Qualitative Disclosures About Market Risk
Chugach is exposed to a variety of risks, including changes in interest rates and changes in commodity prices due to repricing mechanisms inherent in one of our gas supply contracts. In the normal course of our business, we manage our exposure to these risks as described below. We do not engage in trading market risk-sensitive instruments for speculative purposes.
Interest Rate Risk
At December 31, 2015, our short- and long- term debt was comprised of our 2011 and 2012 Series A Bonds, our CoBank bond and outstanding commercial paper.
The interest rates of Chugach’s 2011 Series A Bonds and 2012 Series A Bonds are fixed and set forth in the table below with carrying value and fair value, measured as Level 1 liabilities, (dollars in millions) at December 31, 2015.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Maturing |
| Interest |
| Carrying |
| Fair | |||
2011 Series A, Tranche A |
| 2031 |
| 4.20 | % |
| $ | 72,000 |
| $ | 71,237 |
2011 Series A, Tranche B |
| 2041 |
| 4.75 | % |
|
| 160,333 |
|
| 167,654 |
2012 Series A, Tranche A |
| 2032 |
| 4.01 | % |
|
| 63,750 |
|
| 62,256 |
2012 Series A, Tranche B |
| 2042 |
| 4.41 | % |
|
| 102,000 |
|
| 101,844 |
2012 Series A, Tranche C |
| 2042 |
| 4.78 | % |
|
| 50,000 |
|
| 52,203 |
Total |
|
|
|
|
|
| $ | 448,083 |
| $ | 455,194 |
Chugach is exposed to market risk from changes in interest rates associated with our other credit facilities. Our credit facilities’ interest rates may be reset due to fluctuations in a market-based index, such as the London Interbank Offered Rate (LIBOR) or the base rate or prime rate of our lenders. At December 31, 2015, we had $20.0 million of commercial paper outstanding and $24.9 million outstanding on our CoBank bond. A 100 basis-point rise in interest rates would increase our interest expense by approximately $0.4 million, and a 100 basis point decline in interest rates would decrease our interest expenses by approximately $0.3 million, based on $44.9 million of variable rate debt outstanding at December 31, 2015.
Commodity Price Risk
Chugach has a gas contract that provides for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel and purchased power recovery process, fluctuations in the price paid for gas pursuant to gas supply contracts does not normally impact margins.
40
Item 8 – Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association, Inc. as of December 31, 2015 and 2014, and the related statements of operations, changes in equities and margins, and cash flows for each of the years in the three-year period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Chugach Electric Association, Inc. as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
March 23, 2016
Anchorage, Alaska
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
| December 31, 2015 |
| December 31, 2014 | ||
|
|
|
|
|
|
|
Utility Plant: |
|
|
|
|
|
|
Electric plant in service |
| $ | 1,128,474,292 |
| $ | 1,155,500,963 |
Construction work in progress |
|
| 15,601,374 |
|
| 21,567,341 |
Total utility plant |
|
| 1,144,075,666 |
|
| 1,177,068,304 |
Less accumulated depreciation |
|
| (469,199,226) |
|
| (497,601,371) |
Net utility plant |
|
| 674,876,440 |
|
| 679,466,933 |
|
|
|
|
|
|
|
Other property and investments, at cost: |
|
|
|
|
|
|
Nonutility property |
|
| 76,889 |
|
| 76,889 |
Investments in associated organizations |
|
| 9,635,519 |
|
| 9,923,552 |
Special funds |
|
| 763,913 |
|
| 666,967 |
Restricted cash equivalents |
|
| 1,705,760 |
|
| 1,705,086 |
Total other property and investments |
|
| 12,182,081 |
|
| 12,372,494 |
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
Cash and cash equivalents |
|
| 15,626,919 |
|
| 16,364,962 |
Special deposits |
|
| 74,416 |
|
| 79,390 |
Restricted cash equivalents |
|
| 1,143,467 |
|
| 1,143,000 |
Accounts receivable, less provisions for doubtful accounts |
|
|
|
|
|
|
of $425,751 in 2015 and $346,749 in 2014 |
|
| 28,232,930 |
|
| 36,060,256 |
Materials and supplies |
|
| 27,611,184 |
|
| 26,774,512 |
Fuel stock |
|
| 7,063,541 |
|
| 9,652,073 |
Prepayments |
|
| 1,466,301 |
|
| 2,178,723 |
Other current assets |
|
| 225,079 |
|
| 242,682 |
Total current assets |
|
| 81,443,837 |
|
| 92,495,598 |
|
|
|
|
|
|
|
Deferred charges, net |
|
| 19,492,653 |
|
| 21,376,596 |
|
|
|
|
|
|
|
Total assets |
| $ | 787,995,011 |
| $ | 805,711,621 |
42
Chugach Electric Association, Inc.
Balance Sheets (continued)
December 31, 2015 and 2014
|
|
|
|
|
|
| |
|
|
|
|
|
|
| |
| |||||||
Liabilities, Equities and Margins |
| December 31, 2015 |
| December 31, 2014 | |||
|
|
|
|
|
|
| |
Equities and margins: |
|
|
|
|
|
| |
Memberships |
| $ | 1,661,744 |
| $ | 1,631,569 | |
Patronage capital |
|
| 167,447,781 |
|
| 164,135,053 | |
Other |
|
| 12,527,856 |
|
| 11,158,677 | |
Total equities and margins |
|
| 181,637,381 |
|
| 176,925,299 | |
|
|
|
|
|
|
| |
Long-term obligations, excluding current installments: |
|
|
|
|
|
| |
Bonds payable |
|
| 426,666,665 |
|
| 448,083,332 | |
National Bank for Cooperatives bond payable |
|
| 22,241,852 |
|
| 24,941,165 | |
Total long-term obligations |
|
| 448,908,517 |
|
| 473,024,497 | |
|
|
|
|
|
|
| |
Current liabilities: |
|
|
|
|
|
| |
Current installments of long-term obligations |
|
| 24,115,980 |
|
| 23,889,777 | |
Commercial paper |
|
| 20,000,000 |
|
| 21,000,000 | |
Accounts payable |
|
| 9,701,088 |
|
| 9,746,175 | |
Consumer deposits |
|
| 5,000,684 |
|
| 4,914,260 | |
Fuel cost over-recovery |
|
| 5,135,745 |
|
| 1,462,057 | |
Accrued interest |
|
| 5,915,580 |
|
| 6,191,608 | |
Salaries, wages and benefits |
|
| 7,259,806 |
|
| 7,547,316 | |
Fuel |
|
| 4,942,310 |
|
| 11,137,609 | |
Other current liabilities |
|
| 8,076,903 |
|
| 4,594,865 | |
Total current liabilities |
|
| 90,148,096 |
|
| 90,483,667 | |
|
|
|
|
|
|
| |
Other non-current liabilities: |
|
|
|
|
|
| |
Deferred compensation |
|
| 763,913 |
|
| 666,967 | |
Other liabilities, non-current |
|
| 1,555,329 |
|
| 1,842,000 | |
Deferred liabilities |
|
| 1,802,389 |
|
| 1,858,455 | |
Patronage capital payable |
|
| 11,108,071 |
|
| 10,205,739 | |
Cost of removal obligation |
|
| 52,071,315 |
|
| 50,704,997 | |
Total other non-current liabilities |
|
| 67,301,017 |
|
| 65,278,158 | |
|
|
|
|
|
|
| |
Total liabilities, equities and margins |
| $ | 787,995,011 |
| $ | 805,711,621 |
See accompanying notes to financial statements.
43
Chugach Electric Association, Inc.
Statements of Operations
Years Ended December 31, 2015, 2014 and 2013
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 |
| 2013 | |||
|
|
|
|
|
|
|
|
|
|
Operating revenues |
| $ | 216,421,152 |
| $ | 281,318,513 |
| $ | 305,308,427 |
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
Fuel |
|
| 66,534,877 |
|
| 126,038,350 |
|
| 136,610,262 |
Production |
|
| 16,886,257 |
|
| 21,082,176 |
|
| 21,911,324 |
Purchased power |
|
| 19,599,994 |
|
| 15,608,396 |
|
| 27,836,680 |
Transmission |
|
| 6,287,558 |
|
| 6,138,658 |
|
| 6,624,836 |
Distribution |
|
| 14,089,862 |
|
| 13,002,157 |
|
| 13,225,242 |
Consumer accounts |
|
| 6,117,625 |
|
| 5,887,713 |
|
| 6,014,888 |
Administrative, general and other |
|
| 23,623,299 |
|
| 25,036,248 |
|
| 23,131,149 |
Depreciation and amortization |
|
| 35,652,086 |
|
| 40,179,181 |
|
| 43,384,116 |
Total operating expenses |
| $ | 188,791,558 |
| $ | 252,972,879 |
| $ | 278,738,497 |
|
|
|
|
|
|
|
|
|
|
Interest expense: |
|
|
|
|
|
|
|
|
|
Long-term debt and other |
|
| 22,194,290 |
|
| 23,264,041 |
|
| 24,691,582 |
Charged to construction |
|
| (379,845) |
|
| (463,335) |
|
| (1,310,110) |
Interest expense, net |
| $ | 21,814,445 |
| $ | 22,800,706 |
| $ | 23,381,472 |
Net operating margins |
| $ | 5,815,149 |
| $ | 5,544,928 |
| $ | 3,188,458 |
|
|
|
|
|
|
|
|
|
|
Nonoperating margins: |
|
|
|
|
|
|
|
|
|
Interest income |
|
| 296,788 |
|
| 566,639 |
|
| 686,460 |
Allowance for funds used during construction |
|
| 142,881 |
|
| 163,151 |
|
| 141,014 |
Gain on sale of asset |
|
| 0 |
|
| 0 |
|
| 6,436,992 |
Capital credits, patronage dividends and other |
|
| 248,034 |
|
| 240,827 |
|
| 91,119 |
Total nonoperating margins |
| $ | 687,703 |
| $ | 970,617 |
| $ | 7,355,585 |
|
|
|
|
|
|
|
|
|
|
Assignable margins |
| $ | 6,502,852 |
| $ | 6,515,545 |
| $ | 10,544,043 |
See accompanying notes to financial statements.
44
Chugach Electric Association, Inc.
Statements of Changes in Equities and Margins
Years Ended December 31, 2015, 2014 and 2013
f |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Memberships |
| Other Equities |
| Patronage |
| Total | ||||
Balance, January 1, 2013 | $ | 1,559,344 |
| $ | 11,372,355 |
| $ | 153,832,674 |
| $ | 166,764,373 |
|
|
|
|
|
|
|
|
|
|
|
|
Assignable margins |
| 0 |
|
| 0 |
|
| 10,544,043 |
|
| 10,544,043 |
Retirement/net transfer of capital credits |
| 0 |
|
| 0 |
|
| (1,626,828) |
|
| (1,626,828) |
Unclaimed capital credit retirements |
| 0 |
|
| (21,456) |
|
| 0 |
|
| (21,456) |
Memberships and donations received |
| 40,714 |
|
| 95,019 |
|
| 0 |
|
| 135,733 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2013 |
| 1,600,058 |
|
| 11,445,918 |
|
| 162,749,889 |
|
| 175,795,865 |
|
|
|
|
|
|
|
|
|
|
|
|
Assignable margins |
| 0 |
|
| 0 |
|
| 6,515,545 |
|
| 6,515,545 |
Retirement/net transfer of capital credits |
| 0 |
|
| 0 |
|
| (5,130,381) |
|
| (5,130,381) |
Unclaimed capital credit retirements |
| 0 |
|
| (350,776) |
|
| 0 |
|
| (350,776) |
Memberships and donations received |
| 31,511 |
|
| 63,535 |
|
| 0 |
|
| 95,046 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2014 |
| 1,631,569 |
|
| 11,158,677 |
|
| 164,135,053 |
|
| 176,925,299 |
|
|
|
|
|
|
|
|
|
|
|
|
Assignable margins |
| 0 |
|
| 0 |
|
| 6,502,852 |
|
| 6,502,852 |
Retirement/net transfer of capital credits |
| 0 |
|
| 0 |
|
| (3,190,124) |
|
| (3,190,124) |
Unclaimed capital credit retirements |
| 0 |
|
| 1,298,410 |
|
| 0 |
|
| 1,298,410 |
Memberships and donations received |
| 30,175 |
|
| 70,769 |
|
| 0 |
|
| 100,944 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2015 | $ | 1,661,744 |
| $ | 12,527,856 |
| $ | 167,447,781 |
| $ | 181,637,381 |
See accompanying notes to financial statements.
45
Chugach Electric Association, Inc.
Statements of Cash Flows
Years Ended December 31, 2015, 2014 and 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 |
| 2013 | |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Assignable margins | $ | 6,502,852 |
| $ | 6,515,545 |
| $ | 10,544,043 |
Adjustments to reconcile assignable margins to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
| 35,652,086 |
|
| 40,179,181 |
|
| 43,384,116 |
Amortization and depreciation cleared to operating expenses |
| 4,390,385 |
|
| 5,777,628 |
|
| 5,912,254 |
Allowance for funds used during construction |
| (142,881) |
|
| (163,151) |
|
| (141,014) |
Write off of inventory, deferred charges and projects |
| 691,035 |
|
| 974,062 |
|
| 430,453 |
Gain on sale of Bernice Lake Power Plant |
| 0 |
|
| 0 |
|
| (6,436,992) |
Other |
| (220,496) |
|
| 56,250 |
|
| 240,836 |
(Increase) decrease in assets: |
|
|
|
|
|
|
|
|
Accounts receivable, net |
| 6,866,956 |
|
| 6,879,762 |
|
| 4,823,879 |
Materials and supplies |
| (1,070,896) |
|
| (1,197,127) |
|
| (907,942) |
Fuel stock |
| 2,588,532 |
|
| 3,377,775 |
|
| (3,563,081) |
Prepayments |
| 712,422 |
|
| (315,316) |
|
| 293,455 |
Other assets |
| 215,738 |
|
| 978,338 |
|
| (1,827,291) |
Deferred charges |
| (405,746) |
|
| (1,050,505) |
|
| (317,070) |
Increase (decrease) in liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| (270,416) |
|
| (420,041) |
|
| 1,775,412 |
Consumer deposits |
| 86,424 |
|
| 62,702 |
|
| 571,657 |
Fuel cost over-recovery |
| 3,673,688 |
|
| (173,620) |
|
| (12,074,372) |
Accrued interest |
| (276,028) |
|
| (321,252) |
|
| (294,347) |
Salaries, wages and benefits |
| (287,510) |
|
| (385,047) |
|
| 597,937 |
Fuel |
| (6,195,299) |
|
| (3,696,976) |
|
| (6,033,493) |
Other current liabilities |
| (290,715) |
|
| 1,653,424 |
|
| 1,134 |
Deferred liabilities |
| (123,695) |
|
| 34,668 |
|
| 3,399 |
Net cash provided by operating activities |
| 52,096,436 |
|
| 58,766,300 |
|
| 36,982,973 |
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Return of capital from investment in associated organizations |
| 352,420 |
|
| 351,162 |
|
| 424,484 |
Investment in restricted cash equivalents |
| (1,141) |
|
| (142) |
|
| 0 |
Investment in marketable securities |
| 0 |
|
| (217,817) |
|
| (327,175) |
Proceeds from the sale of marketable securities |
| 0 |
|
| 10,522,620 |
|
| 0 |
Proceeds from capital grants |
| 2,395,331 |
|
| 6,960,143 |
|
| 20,329,782 |
Extension and replacement of plant |
| (35,094,355) |
|
| (30,303,133) |
|
| (64,473,966) |
Net cash used in investing activities |
| (32,347,745) |
|
| (12,687,167) |
|
| (44,046,875) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from short-term obligations |
| 23,000,000 |
|
| 22,000,000 |
|
| 45,500,000 |
Repayments of short-term obligations |
| (24,000,000) |
|
| (31,000,000) |
|
| (27,000,000) |
Repayments of long-term obligations |
| (23,889,777) |
|
| (24,682,812) |
|
| (24,493,022) |
Memberships and donations received |
| 357,365 |
|
| (255,730) |
|
| 114,277 |
Retirement of patronage capital and estate payments |
| (182,352) |
|
| (4,114,541) |
|
| (156,565) |
Net receipts on consumer advances for construction |
| 4,228,030 |
|
| 3,991,749 |
|
| 3,398,906 |
Net cash used in financing activities |
| (20,486,734) |
|
| (34,061,334) |
|
| (2,636,404) |
Net change in cash and cash equivalents |
| (738,043) |
|
| 12,017,799 |
|
| (9,700,306) |
Cash and cash equivalents at beginning of period | $ | 16,364,962 |
| $ | 4,347,163 |
| $ | 14,047,469 |
Cash and cash equivalents at end of period | $ | 15,626,919 |
| $ | 16,364,962 |
| $ | 4,347,163 |
Supplemental disclosure of non-cash investing and financing activities: |
|
|
|
|
|
|
|
|
Cost of removal obligation | $ | 1,366,318 |
| $ | 3,565,605 |
| $ | 2,511,077 |
Extension and replacement of plant included in accounts payable | $ | 2,582,947 |
| $ | 2,382,117 |
| $ | 3,817,788 |
Patronage capital retired and included in other current liabilities | $ | 2,105,440 |
| $ | 2,572,670 |
| $ | 2,512,753 |
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized | $ | 21,891,308 |
| $ | 21,835,216 |
| $ | 21,839,391 |
See accompanying notes to financial statements.
46
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Chugach Electric Association, Inc. (Chugach) is the largest electric utility in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity to directly serve retail customers 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 (Seward), as a wholesale customer. We provided much of the power requirements of Matanuska Electric Association, Inc. (MEA) and Homer Electric Association, Inc. (HEA) through their contract expiration dates of April 30, 2015, and December 31, 2013, respectively. 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.
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 regulatory authority of the Regulatory Commission of Alaska (RCA).
(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 allowance for doubtful accounts, workers’ compensation, deferred charges and credits, unbilled revenue, the estimated useful life of utility plant and the cost of removal obligation. 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 (2j) – “Deferred Charges and Credits.”
47
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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, less salvage, is charged to accumulated depreciation. The removal cost is charged to cost of removal obligation. 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, 2015 are as follows:
Annual Depreciation Rate Ranges
|
|
|
|
|
|
|
|
|
|
Steam production plant |
| 4.81% | - | 7.04% |
Hydroelectric production plant |
| 1.06% | - | 3.00% |
Other production plant |
| 3.98% | - | 10.15% |
Transmission plant |
| 1.58% | - | 7.86% |
Distribution plant |
| 2.17% | - | 9.63% |
General plant |
| 1.57% | - | 20.00% |
Other |
| 2.75% | - | 2.75% |
Southcentral Power Project (SPP) steam production plant |
| 3.09% | - | 3.46% |
SPP other production plant |
| 3.15% | - | 3.84% |
On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. 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.
On August 31, 2012, in Docket U-12-009, the RCA approved Southcentral Power Project (SPP) depreciation rates effective February 1, 2013, the date the SPP plant was placed in service.
48
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
d. 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 excluding SPP, Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.3% during 2015 and 2014 and 3.7% during 2013. For SPP, Chugach capitalized actual interest expense and related fees associated with its construction.
e. 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 2015, 2014 and 2013.
f. 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.
Consumer deposits – the carrying amount approximates fair value because of the short refunding term.
Long‑term obligations – the fair value is estimated based on the quoted market price for same or similar issues (see note 11).
Restricted cash – the carrying amount approximates fair value because of the short maturity of those instruments.
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.
g. 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 $6,218,015 and $6,300,149 during the years ended December 31, 2015 and 2014, respectively.
49
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Restricted cash equivalents include funds on deposit for future workers’ compensation claims and interim rates collected from customers and escrowed as required by the RCA. At December 31, 2015 and 2014, restricted cash equivalents included $2.8 million of funds on deposit for future workers’ compensation claims. At December 31, 2015 and 2014, there were no restricted cash equivalents representing interim rates collected from customers.
h. 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 receivable are invoiced amounts to Anchorage Municipal Light & Power (ML&P) for their proportionate share of current SPP costs, which amounted to $1.1 million and $0.9 million in 2015 and 2014, respectively. In addition, accounts receivable includes invoiced amounts for grants to support the construction of facilities to divert water and safely transmit electricity, which amounted to $0.2 million and $1.1 million in 2015 and 2014, respectively.
i. Materials and Supplies
Materials and supplies are stated at average cost.
j. Deferred Charges and Credits
In accordance with FASB ASC 980, Chugach’s financial statements reflect regulatory assets 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 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 credits, primarily representing regulatory liabilities, are amortized to operating expense over the period required for ratemaking purposes. It also includes refundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition. If events or circumstances should
50
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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.
k. 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.
l. 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 $10,531,377 and $9,885,526 of unbilled retail revenue at December 31, 2015 and 2014, respectively. 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.
m. Fuel and Purchased Power Cost Recovery
Expenses associated with electric services include fuel used to generate electricity and 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 purchase 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. Fuel costs were over-recovered by $5,135,745 and by $1,462,057 in 2015 and 2014, respectively. Total fuel and purchased power costs in 2015, 2014, and 2013 were $86,134,871, $141,646,746, and $164,446,942, respectively.
51
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
n. 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.
o. 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, 2015, 2014 and 2013 was in compliance with that provision. In addition, as described in Note (15) – “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, 2013 through December 31, 2015 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2015.
p. Consumer Deposits
Consumer deposits are the amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2015 and 2014, totaled $3.1 million and $2.9 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances for the years ended December 31, 2015 and 2014 totaled $1.9 million and $2.0 million, respectively.
q. Grants
Chugach has received federal and state grants to offset storm related expenditures and to support 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 against the actual expense incurred, which totaled $1.6 million and $4.8 million in 2015 and 2014, respectively.
52
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
r. Fuel Stock
Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natural Gas Storage Alaska (CINGSA), which began service in the second quarter of 2012. Chugach’s fuel balance in storage for the years ended December 31, 2015 and 2014 amounted to $7.1 million and $9.7 million, respectively.
s. Corrections
For the year ended December 31, 2015, Chugach recorded the following correction for the year ended December 31, 2014:
A correction representing the long-term versus current presentation of long-term obligations associated with bonds payable, previously reported as current installments of long-term obligations and now reported as long-term obligations, excluding current installments. The impact of this correction was an increase to long-term obligations, excluding current installments, and a decrease to current installments of long-term obligations of $1.0 million as of December 31, 2014.
For the year ended December 31, 2015, Chugach recorded the following correction for the years ended December 31, 2014 and 2013:
A correction representing the cash received from customers for the undergrounding ordinance, included in net receipts on consumer advances for construction, previously reported as other current liabilities. The impact of this correction was a decrease in cash provided by operating activities and cash used in financing activities of $3.2 million and $2.9 million for the years ended December 31, 2014 and 2013, respectively.
(3) Accounting Pronouncements
Issued, not yet adopted:
ASC Update 2014-09 “Revenue from Contracts with Customers (Topic 606)”
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. This update was effective for fiscal years beginning after December 15, 2016, for which early adoption was prohibited. However, in August of 2015, the FASB issued ASC Update 2014-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” deferring the effective date of ASC Update 2014-09 to fiscal years beginning after December 15, 2017, and permitting early adoption of this update, but only for annual reporting periods beginning after December 15, 2016, and interim reporting periods within that reporting period. The standard permits the use of either the retrospective or cumulative effect transition method. Chugach has not yet selected a transition method and is evaluating the effect on its results of operations, financial position, and cash flows.
53
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
ASC Update 2015-03 “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs”
In April of 2015, the FASB issued ASC Update 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASC Update 2015-03 revises the presentation guidance for debt issuance costs related to a recognized debt liability. The effect of this update is to present the debt issuance costs as a direct deduction to the liability on the balance sheet and retrospective application is required. This update does not change the recognition and measurement guidance for debt issuance costs. This update is effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach will begin application of ASC 2015-03 with the annual report for the year ended December 31, 2016. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.
ASC Update 2015-15 “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements”
In September of 2015, the FASB issued ASC Update 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” ASC Update 2015-15 amends guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements for SEC reporting. This update is effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach will begin application of ASC 2015-15 with the annual report for the year ended December 31, 2016. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.
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, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.
54
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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 is evaluating the effect on its results of operations, financial position, and cash flows.
(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.
Chugach had no Level 2 or 3 assets or liabilities measured at fair value on a recurring basis. Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions.
55
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
(5) Regulatory Matters
MEA Interim Power Sales Agreement
On August 12, 2014, MEA notified Chugach that their newly constructed power plant, the Eklutna Generation Station (EGS), would not be completed by January 1, 2015. On September 30, 2014, Chugach entered into an Interim Power Sales Agreement (Agreement) to provide MEA with all demand and energy requirements on a firm basis based on existing tariff rates for a minimum one quarter period beginning on January 1, 2015, and ending on March 31, 2015. Under the terms of the agreement, Chugach agreed to purchase from MEA the output of up to four units from their plant upon commercial operation through the term of the agreement. Chugach proposed to purchase the pooled energy and recover the costs from its members, including MEA, through Chugach’s fuel and purchased power adjustment process. MEA supplied and delivered all additional gas and attendant transportation necessary for Chugach to produce electric service to MEA arising as a result of the electric services to be provided by Chugach pursuant to the Agreement.
On December 22, 2014, the RCA approved both the Agreement and Chugach’s proposal to recover costs incurred under the Agreement through its fuel and purchased power rate adjustment process. As part of the approval, the RCA required Chugach to provide monthly information on MEA gas deliveries to Chugach, system heat rates with and without EGS, and the number of EGS units made commercially available during each month of the contract.
On January 30, 2015, MEA notified Chugach that it had four units available to pool with Chugach units to meet the combined system load of Chugach and MEA. These units were subsequently pooled with Chugach units.
The term of the Agreement was subsequently extended to and expired on April 30, 2015.
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 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. As a result, Chugach is receiving $40,000 per month from MEA for these services. The Dispatch Services Agreement remains in effect through March 31, 2016.
56
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
In December of 2015, MEA notified Chugach that it would not be extending the Dispatch Services Agreement for the dispatch of electric service. Chugach and MEA have discussed modification of the Dispatch Agreement. At this time, a final agreement has not been reached.
June 2014 Test Year General Rate Case
Chugach’s June 2014 test year rate case was submitted to the RCA on February 13, 2015. Chugach requested a system base rate increase of approximately $21.3 million, or 20% on total base rate revenues for rates effective in April 2015. The filing also included updates to firm and non-firm transmission wheeling rates and attendant ancillary services in support of third-party transactions on the Chugach transmission system. The primary driver of the rate changes was the reduction in fixed-cost contributions resulting from the March 31, 2015 expiration of the Interim Power Sales Agreement between Chugach and MEA.
Chugach submitted proposed adjustments to its fuel and purchased power rates under a separate tariff advice letter to become effective at the same time which allows interim base rate increases to be synchronized with reductions in fuel costs resulting from system heat rate improvements and a greater share of hydroelectric generation used to meet the load requirements of the remaining customers on the system. In combination with Chugach’s fuel and purchased power rate adjustment filing for rates effective in April 2015, the effective increase to retail customer bills was approximately between two and five percent.
The RCA issued Order U-15-081(1) on April 30, 2015, suspending the filing and granting Chugach’s request for interim and refundable rate increases effective May 1, 2015. A scheduling conference was held on May 27, 2015. On June 4, 2015, the RCA issued Order U-15-081(2), granting approval for intervention by HEA, MEA and GVEA. The RCA indicated that a final order in the case will be issued by May 8, 2016. Intervenor responsive testimony was filed by the Attorney General (AG) and MEA on October 28, 2015. The AG’s testimony focused on revenue requirement matters and MEA’s testimony focused on transmission cost allocation issues. Chugach’s responsive testimony was filed on December 15, 2015.
In January of 2016, Chugach and the Attorney General (AG) for the State of Alaska entered into settlement discussions to resolve revenue requirement matters in the case, which resulted in settlement of all outstanding matters related to the determination of Chugach’s system revenue requirement for both the interim and permanent rate periods. As a result, Chugach agreed to reduce its revenue requirement by 0.5% (approximately $0.6 million). In addition, the stipulation provides for a permanent increase in Chugach’s system Times Interest Earned Ratio (TIER) from 1.30 to 1.35, which represents an approximate margin increase of $1.0 million per year. The stipulation was filed with the RCA on January 21, 2016. The RCA has not issued a ruling on the settlement. If the settlement is accepted, Chugach will reduce its revenue requirement by $0.6 million and expects to issue refunds on demand and energy rates for bills issued during the interim rate period.
The adjudicatory hearing was held from January 25 through January 28, 2016, to address transmission-related matters identified by MEA. Because of the settlement, no revenue requirement matters were addressed during the hearing. A final order in the case is expected by May 8, 2016.
57
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Chugach expects to resume its participation in the SRF process at the conclusion of this case. SRF is an expedited process available to electric cooperatives in Alaska for routine updates to demand and energy rates.
Fire Island Wind Project
On October 10, 2011, the RCA issued an order approving Chugach’s request for assurance of cost recovery associated with a new power purchase agreement (PPA) between Chugach and Fire Island Wind, LLC (FIW), a special purpose entity wholly-owned by Cook Inlet Region, Inc.
Associated with the approval of the PPA, Chugach submitted project status reports on March 31, 2012, June 29, 2012, October 31, 2012, and January 16, 2013. On January 30, 2014, Chugach submitted a status report regarding FIW integration and a cost reimbursement agreement related to possible impacts to an interconnected utility as a result of the project. On July 25, 2014, the RCA issued Order No. 4 approving Chugach’s request to file its next status update by September 30, 2014. Chugach filed a status report with the RCA on September 26, 2014. In the filing, Chugach informed the RCA that it had received notification from ML&P that they believe no further proceedings on this matter are necessary. ML&P indicated that fluctuations from the wind project are impacting system frequency but the attendant costs associated with quantifying the impacts likely exceed the attendant benefit. ML&P reserved the right to open this issue at a later time. In the filing, Chugach indicated that it will continue to evaluate the potential impact of the Fire Island Wind Project on the grid and requested that the RCA accept the status report on the integration and cost reimbursement issues and close the docket.
The RCA issued an order in February of 2015 requiring ML&P to file a separate report addressing the nature and estimate of any adverse cost impacts attributable to FIW integration, as well as the estimated costs and equipment needed for measurement. ML&P submitted its compliance filing in April of 2015 addressing the type and range of costs ML&P might experience if it sought to isolate and identify the integration impacts of the FIW Project. In a subsequent order, the RCA acknowledged ML&P’s compliance filing and closed the docket.
AIX Energy LLC: March 1, 2015, through February 29, 2016
On December 22, 2014, Chugach executed an agreement (AIX Agreement) with AIX Energy LLC (AIX) which allows for natural gas purchases by Chugach from AIX beginning March 1, 2015, through February 29, 2016. The AIX Agreement provides flexibility in both the purchase price and volumes, with specific prices and volumes to be determined by each transaction. However, the price of gas cannot exceed $6.24 per thousand cubic feet (Mcf) and the total volume of gas is capped at 300,000 Mcf, or a maximum total outlay of approximately $1.9 million.
As the AIX Agreement is for a term less than one year, approval of the agreement by the RCA is not required; however, Chugach submitted a filing to the RCA seeking approval to recover purchases made under the agreement as a new cost element in its fuel and purchased power adjustment process. This agreement was subsequently approved by the RCA.
58
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
AIX Energy LLC: 2016 through March 31, 2029
Chugach entered into a long-term gas contract with AIX, entitled, “Gas Sale and Purchase Agreement between AIX Energy LLC and Chugach” (AIX GSPA), that extends through March 31, 2024, with an option to extend the term an additional 5-year period through March 31, 2029. Under the AIX GSPA, Chugach is permitted to purchase gas as either firm or interruptible, with the specific purchase price and quantity negotiated at the time of each transaction, subject to a maximum price and quantity in each contract year. There is no minimum purchase requirement contained in the AIX GSPA and the purchase price is determined through mutual agreement of Chugach and AIX, subject to a maximum price in each contract year. The AIX GSPA provides Chugach with additional diversity in its gas supply portfolio with the opportunity to purchase gas at prices below existing supplier prices.
The AIX GSPA was filed with the RCA on November 25, 2015, and approved in a letter order issued on January 11, 2016.
Second and Third Amendments to the Gas Sale and Purchase Agreement with Hilcorp
Chugach submitted the Second Amendment (Second Amendment) to the GSPA between Hilcorp Alaska, LLC and Chugach to the RCA on March 19, 2015. The Second Amendment was administrative in nature and established a more efficient payment procedure and updated notice provisions required under the GSPA. The Second Amendment was approved by the RCA on April 20, 2015.
On July 23, 2015, Chugach filed the Third Amendment (Third Amendment) to the GSPA between Hilcorp Alaska, LLC and Chugach with the RCA. The Third Amendment extends the term of the existing GSPA for firm gas sales from March 31, 2019 to March 31, 2023, and adjusts the volumes and gas price for purchases in 2019. The Third Amendment does not change the underlying terms and conditions of the GSPA as amended, or the pricing and gas quantities in 2015 through March 31, 2018. The Third Amendment reduces the gas price by 8.5 percent on April 1, 2018.
A key provision of the Third Amendment is the option for additional gas volumes during the period of April 1, 2019, through March 31, 2023, on both an annual contract quantity and average daily contract quantity basis. These options provide Chugach with added flexibility in the overall management of its gas supply requirements. The annual volumetric basis option provides Chugach with the ability to augment its firm gas supply requirements from other independent suppliers. Chugach is permitted to increase the annual contract volumes of up to 1.1 billion cubic feet (Bcf) of gas beginning April 1, 2019, and up to 2.6 Bcf annually on April 1 thereafter, provided advanced notice is given to Hilcorp. This option allows Chugach to continue to obtain firm gas supplies from Hilcorp or alternatively from other gas suppliers if market conditions allow.
The Third Amendment also provides Chugach with shorter-term options to purchase up to 2.0 million cubic feet (MMcf) per day of additional firm gas without impacting established annual contract quantities. This option allows Chugach to purchase additional volumes in response to short-term sales increases due to weather, bulk power maintenance activities, or other events on the Chugach system.
59
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
The Third Amendment was approved by the RCA on September 8, 2015.
2013 General Rate Case
To reflect revenue and cost changes resulting from the expiration of HEA’s wholesale contract, Chugach submitted its 2013 Test Year General Rate Case to the RCA on November 19, 2013, to increase system base rate revenues by $16.0 million, or approximately 12.5% on total retail, MEA, and Seward base rate revenues of $127.4 million. On January 2, 2014, the RCA approved the submitted rates on an interim and refundable basis. Retail rates were effective January 2, 2014, and wholesale rate changes were effective February 1, 2014, for purchases beginning January 1, 2014. The increase, net of both base rate increases and fuel savings, to Chugach retail end-users was approximately six percent.
On April 18, 2014, Chugach submitted an update to its 2013 general rate case to reflect the final results contained in Chugach’s compliance filing in the 2012 general rate case that was submitted to the RCA on April 14, 2014. The update reflected final rate design changes contained in the 2012 rate case. On May 30, 2014, the RCA issued Order No. 3 approving Chugach’s motion and update to retail and wholesale base rates effective with the first billing cycle in June 2014. There was no impact to the system revenue requirement contained in the 2013 Test Year General Rate Case filing.
Chugach and the parties to the docket entered into a stipulation resolving revenue requirement and cost of service matters contained in the case. The stipulation was filed with the RCA on October 16, 2014, and required Chugach to issue refunds totaling $1.1 million (annualized) for service provided beginning January 2014, with an expected financial impact to Chugach of approximately $0.2 million on an annual basis. The stipulation contained a provision that Chugach be permitted to create a regulatory asset for approximately $0.9 million of storm-related costs and be permitted to recover $0.2 million per year over the next five years. On November 13, 2014, the RCA accepted the stipulation.
On February 12, 2015, the RCA issued Order No. 9 of U-14-001 accepting the stipulation on revenue requirement matters and resolving the remaining issues in the docket. The RCA required Chugach to submit updated tariffs reflecting the results of the RCA order and the stipulations entered into the case, including a detailed refund plan, which Chugach submitted on March 13, 2015.
The RCA issued Order U-14-001(11) on April 30, 2015, approving final rates for the January 1, 2014, through April 30, 2015, period, and approving Chugach’s refund plan resulting from settlements in the case. Chugach issued refunds to Seward, MEA and transmission wheeling customers in May of 2015, and to retail customers between June and July of 2015. On August 6, 2015, in compliance with Order U-14-001(11), Chugach notified the RCA that it had completed the disbursement of refunds to retail and wholesale customers. On August 25, 2015, the RCA issued Order U-14-001(12) closing the docket.
60
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Operation and Regulation of the Alaska Railbelt 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. The RCA held public meetings and workshops throughout the second quarter of 2015.
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 also wants to be granted authority for siting new generation and transmission and to regulate integrated resource planning of the Railbelt electrical system. Quarterly progress reports on this effort were required for the remainder of 2015. The development of common Railbelt operating and reliability standards and system-wide merit order economic dispatch of the Railbelt’s electrical generation units to bring the maximum benefit to ratepayers was also recommended. The RCA expects to analyze and review present efforts in order to assess the organizational and governance structure needed for an independent consolidated system operator. Initial progress reports to develop an independent Railbelt electric transmission company were filed with the RCA on September 30, 2015. A second report on grid unification was filed with the RCA in December 2015. Progress reports associated with system-wide economic dispatch were filed with the RCA in January and early February 2016.
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. Chugach intends to finalize this review and evaluation in the first or second quarter of 2016. While Chugach cannot determine the materiality of any effect on its results of operations, financial condition, and cash flows until a business model and plan are adopted, it anticipates a positive outcome.
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 now proposes to establish guidelines for commercial sales of at least 2 Bcf of this gas. Chugach submitted comments to the RCA regarding CINGSA’s proposed treatment of found gas. Chugach does 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 intervenors 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.
61
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
The RCA issued a final order in the case on December 4, 2015, ruling significantly in favor of the intervenors 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, errored, 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.
ENSTAR Natural Gas
ENSTAR Natural Gas Company (ENSTAR) submitted a general rate case to the RCA proposing a 20% system rate increase, and an approximate 100% increase to Chugach for gas transportation services. Chugach submitted responsive testimony in May 2015. ENSTAR submitted reply testimony on June 26, 2015.
Chugach and other parties to the docket entered into mediation in mid-July and reached an agreement to settle in principal the outstanding issues in the case. As a result of the stipulation, the original proposed annual increase of $2.6 million to Chugach was settled at less than $0.5 million. The parties also agreed to several tariff changes that remove demand charge penalties for economy transactions. The hearing originally scheduled to begin in late August was vacated. The RCA accepted the stipulation. ENSTAR is required to file another general rate case in the second quarter of 2016.
Beluga River Unit
In July of 2015, ConocoPhillips Alaska, Inc. (COP) announced the marketing for sale of its North Cook Inlet Unit; its interest in the Beluga River Unit (BRU); and its interest in 5,700 acres of exploration prospects in the Cook Inlet region. In October of 2015, Chugach submitted a joint bid with the Municipality of Anchorage d/b/a Municipal Light & Power (ML&P) for acquisition of COP’s one-third working interest in the BRU.
As discussed in “Note 17 – Subsequent Events – Beluga River Unit,” Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” (Purchase and Sale Agreement) on February 4, 2016. The Purchase and Sale Agreement transfers COP’s interest in the BRU to Chugach and ML&P. The acquisition and attendant recovery of costs in electric rates is subject to the approval of the RCA.
62
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Chugach and ML&P expect to submit a joint petition to the RCA for approval of the Purchase and Sale Agreement in March of 2016. Chugach expects a two to six month process for RCA review of the Purchase and Sale Agreement. A separate filing detailing the specific rate recovery process is expected to be filed in the second quarter of 2016. Under the recovery structure that will be proposed by Chugach, costs associated with the BRU, including acquisition and on-going operations, maintenance and capital investment, will be recovered on a dollar-for-dollar basis through Chugach’s quarterly fuel adjustment process. Chugach recovers its fuel and purchased power costs as a direct pass-through from its retail and wholesale customers with minimal lag between cost incurrence and recovery.
(6) Utility Plant
Major classes of utility plant as of December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Electric plant in service: | 2015 |
| 2014 | ||
Steam production plant | $ | 100,938,247 |
| $ | 161,454,274 |
Hydroelectric production plant |
| 20,591,678 |
|
| 20,594,429 |
Other production plant |
| 284,035,865 |
|
| 278,389,073 |
Transmission plant |
| 277,490,606 |
|
| 261,173,934 |
Distribution plant |
| 290,680,919 |
|
| 281,706,456 |
General plant |
| 51,841,582 |
|
| 53,452,136 |
Unclassified electric plant in service1 |
| 95,611,615 |
|
| 91,446,881 |
Intangible plant1 |
| 5,455,371 |
|
| 5,455,371 |
Other1 |
| 1,828,409 |
|
| 1,828,409 |
Total electric plant in service |
| 1,128,474,292 |
|
| 1,155,500,963 |
Construction work in progress |
| 15,601,374 |
|
| 21,567,341 |
Total electric plant in service and construction work in progress | $ | 1,144,075,666 |
| $ | 1,177,068,304 |
1Unclassified 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.
63
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
(7) Investments in Associated Organizations
Investments in associated organizations include the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 | ||
NRUCFC | $ | 6,095,980 |
| $ | 6,095,980 |
CoBank |
| 3,475,664 |
|
| 3,763,697 |
NRUCFC Capital Term Certificates and other |
| 63,875 |
|
| 63,875 |
Total investments in associated organizations | $ | 9,635,519 |
| $ | 9,923,552 |
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.
(8) Deferred Charges and Credits
Deferred Charges
Deferred charges, or regulatory assets, net of amortization, consisted of the following at December 31:
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|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 | ||
Debt issuance and reacquisition costs | $ | 2,928,378 |
| $ | 3,263,937 |
Refurbishment of transmission equipment |
| 114,198 |
|
| 123,457 |
Feasibility studies |
| 551,122 |
|
| 578,806 |
Beluga gas compression |
| 508,866 |
|
| 1,017,733 |
Cooper Lake relicensing / projects |
| 5,410,109 |
|
| 5,540,212 |
Fuel supply |
| 939,768 |
|
| 898,849 |
Storm damage |
| 841,595 |
|
| 971,071 |
Other regulatory deferred charges |
| 1,257,809 |
|
| 1,464,784 |
Bond interest - market risk management |
| 5,871,286 |
|
| 6,402,875 |
Environmental matters |
| 1,069,522 |
|
| 1,114,872 |
Total deferred charges | $ | 19,492,653 |
| $ | 21,376,596 |
64
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Deferred charges, or regulatory assets, not currently being recovered in rates charged to consumers, consisted of the following at December 31:
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|
|
|
|
|
|
|
|
| 2015 |
| 2014 | ||
Studies and other | $ | 686,348 |
| $ | 387,253 |
Storm damage |
| 0 |
|
| 971,071 |
Wind project |
| 0 |
|
| 34,543 |
Total deferred charges | $ | 686,348 |
| $ | 1,392,867 |
The amount related to storm damage was approved by the RCA on February 21, 2015, see Note (5) – Regulatory Matters – 2013 General Rate Case.”
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 Credits
Deferred credits, or regulatory liabilities, at December 31 consisted of the following:
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|
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|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 | ||
Refundable consumer advances for construction | $ | 823,115 |
| $ | 787,824 |
Estimated initial installation costs for meters |
| 105,274 |
|
| 98,964 |
Post retirement benefit obligation |
| 874,000 |
|
| 874,000 |
Other |
| 0 |
|
| 97,667 |
Total deferred costs | $ | 1,802,389 |
| $ | 1,858,455 |
(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 December 31, 2015, Chugach had $167,447,781 of patronage capital (net of capital credits retired in 2015), which included $160,944,929 of patronage capital that had been assigned and $6,502,852 of patronage capital to be assigned to its members. At December 31, 2014, Chugach had $164,135,053 of patronage capital (net of capital credits retired in 2014), which included $157,619,508 of patronage capital that had been assigned and $6,515,545 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. In December of 2013, the Board resumed its capital credit retirement program.
65
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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. HEA’s patronage capital payable was $7.9 million at December 31, 2015 and 2014, respectively.
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 $3.2 million and $2.3 million at December 31, 2015 and 2014, respectively.
The Second Amended and Restated Indenture of Trust (the Indenture) and the CoBank 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 liabilities and equities and margins. Capital credits retired, net of HEA’s allocations, were $3,190,124, $5,130,381, and $1,626,828 for the years ended December 31, 2015, 2014, and 2013, 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, 2015, 2014, and 2013 was $2,105,440, $1,042,064 and $1,470,263, respectively.
(10) Other Equities
A summary of other equities at December 31 follows:
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|
|
|
|
|
|
|
|
|
|
|
| 2015 |
| 2014 | ||
Nonoperating margins, prior to 1967 | $ | 23,625 |
| $ | 23,625 |
Donated capital |
| 1,877,193 |
|
| 1,806,424 |
Unclaimed capital credit retirement1 |
| 10,627,038 |
|
| 9,328,628 |
Total other equities | $ | 12,527,856 |
| $ | 11,158,677 |
1Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska’s unclaimed property law and has therefore reverted to Chugach.
66
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
(11) Debt
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Long-term obligations at December 31 are as follows: | 2015 |
| 2014 | ||
2011 CoBank bond, 2.77% variable rate bond maturing in 2022, with interest payable monthly and principal due annually beginning in 2003 | $ | 24,941,165 |
| $ | 27,414,275 |
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 |
| 72,000,000 |
|
| 76,500,000 |
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 |
| 160,333,332 |
|
| 166,499,999 |
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 |
| 63,750,000 |
|
| 67,500,000 |
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 |
| 102,000,000 |
|
| 109,000,000 |
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 |
Total long-term obligations | $ | 473,024,497 |
| $ | 496,914,274 |
Less current installments |
| 24,115,980 |
|
| 23,889,777 |
Long-term obligations, excluding current installments | $ | 448,908,517 |
| $ | 473,024,497 |
Covenants
Chugach is required to comply with all covenants set forth in the Indenture that secures the 2011 Series A Bonds, the 2012 Series A Bonds and the 2011 CoBank bond. The CoBank bond is governed by the Amended and Restated Master Loan Agreement, which is now secured by the Indenture dated January 20, 2011.
Chugach is also required to comply with the 2010 Credit Agreement, between Chugach and NRUCFC, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch as amended June 29, 2012, governing loans and extensions of credit associated with Chugach’s Commercial Paper Program, in an aggregate principal amount not exceeding $100.0 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.
67
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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 CoBank Master Loan Agreement also required Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. The Amended and Restated Master Loan Agreement with CoBank, which became effective on January 19, 2011, did not change this requirement.
The 2010 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.
68
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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 liabilities and equities and margins.
Maturities of Long‑term Obligations
Long-term obligations at December 31, 2015, mature as follows:
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Year ending |
|
| 2011 Series A |
|
| CoBank Bond |
|
| 2012 Series A |
|
| Total |
2016 |
|
| 10,666,667 |
|
| 2,699,313 |
|
| 10,750,000 |
|
| 24,115,980 |
2017 |
|
| 10,666,667 |
|
| 2,945,954 |
|
| 10,750,000 |
|
| 24,362,621 |
2018 |
|
| 10,666,667 |
|
| 3,215,267 |
|
| 10,750,000 |
|
| 24,631,934 |
2019 |
|
| 10,666,667 |
|
| 3,509,142 |
|
| 10,750,000 |
|
| 24,925,809 |
2020 |
|
| 10,666,667 |
|
| 3,829,809 |
|
| 10,750,000 |
|
| 25,246,476 |
Thereafter |
|
| 178,999,997 |
|
| 8,741,680 |
|
| 162,000,000 |
|
| 349,741,677 |
|
| $ | 232,333,332 |
| $ | 24,941,165 |
| $ | 215,750,000 |
| $ | 473,024,497 |
Lines of credit
Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2015 or 2014, and therefore had no outstanding balance at December 31, 2015 and 2014. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was 2.90% at December 31, 2015 and 2014.
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 expires October 12, 2017, and is immediately available for unconditional borrowing.
Commercial Paper
On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper Program. The participating banks were NRUCFC, Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch. Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement to update the pricing and extend the term. The new pricing includes an all-in drawn spread of one month London Interbank Offered Rate (LIBOR)
69
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
plus 107.5 basis points, along with a 17.5 basis points facility fee (based on an A- unsecured debt rating). The Amended Unsecured Credit Agreement now expires on November 17, 2016. The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch. Our commercial paper can be repriced between one day and 270 days. Chugach is expected to continue to issue commercial paper in 2016, as needed, however, the requirement for short-term borrowing has decreased.
Chugach had $20.0 million and $21.0 million of commercial paper outstanding at December 31, 2015 and 2014, respectively.
The following table provides information regarding 2015 monthly average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:
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Month |
| Average Balance |
| Weighted Average |
| Month |
| Average Balance |
| Weighted Average Interest Rate | ||
January 2015 |
| $ | 17.8 |
| 0.26 |
| July 2015 |
| $ | 10.1 |
| 0.26 |
February 2015 |
| $ | 11.6 |
| 0.22 |
| August 2015 |
| $ | 12.0 |
| 0.25 |
March 2015 |
| $ | 16.0 |
| 0.29 |
| September 2015 |
| $ | 19.5 |
| 0.25 |
April 2015 |
| $ | 23.8 |
| 0.28 |
| October 2015 |
| $ | 24.0 |
| 0.25 |
May 2015 |
| $ | 16.0 |
| 0.27 |
| November 2015 |
| $ | 22.4 |
| 0.25 |
June 2015 |
| $ | 12.1 |
| 0.31 |
| December 2015 |
| $ | 21.4 |
| 0.49 |
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.
70
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
The following table provides additional information regarding the 2011 Series A and 2012 Series A bonds at December 31, 2015:
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| Maturing |
| Average |
| Interest |
| Issue |
| Carrying | |||
2011 Series A, Tranche A |
| 2031 |
| 10.0 |
| 4.20 | % |
| $ | 90,000 |
| $ | 72,000 |
2011 Series A, Tranche B |
| 2041 |
| 15.5 |
| 4.75 | % |
|
| 185,000 |
|
| 160,333 |
2012 Series A, Tranche A |
| 2032 |
| 10.7 |
| 4.01 | % |
|
| 75,000 |
|
| 63,750 |
2012 Series A, Tranche B |
| 2042 |
| 15.7 |
| 4.41 | % |
|
| 125,000 |
|
| 102,000 |
2012 Series A, Tranche C |
| 2042 |
| 20.7 |
| 4.78 | % |
|
| 50,000 |
|
| 50,000 |
Total |
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|
|
|
| $ | 525,000 |
| $ | 448,083 |
Chugach has a term loan facility with CoBank. Loans made under this facility are evidenced by the 2011 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated January 19, 2011, and secured by the Indenture.
Fair Value of Debt Instruments
The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach. Level 1 measurement was used to determine the fair value of the 2011 and 2012 Series A Bonds. Level 2 measurements were used to determine all other long-term obligations. The estimated fair value (in thousands) of the long-term obligations included in the financial statements at December 31 is as follows:
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| Carrying Value |
| Fair Value | ||
Long-term obligations (including current installments) | $ | 473,024 |
| $ | 480,135 |
(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.
71
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Chugach made contributions to all significant pension plans for the years ended December 31, 2015, 2014 and 2013 of $6.7 million, $6.8 million and $6.8 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2015, 2014 and 2013.
The following table provides information regarding pension plans which Chugach considers individually significant:
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| Alaska Electrical Pension Plan3 |
| NRECA Retirement Security Plan3 | ||||
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, 2017 |
| N/A2 | ||||
Subject to Funding Improvement Plan | No |
| No4 | ||||
Surcharge Paid | N/A |
| N/A4 | ||||
| 2015 | 2014 | 2013 |
| 2015 | 2014 | 2013 |
Zone Status | Green | Green | Green |
| N/A1 | N/A1 | N/A1 |
Required minimum contributions | None | None | None |
| N/A | N/A | N/A |
Contributions (in millions) | $3.1 | $3.3 | $3.4 |
| $3.5 | $3.5 | $3.4 |
Contributions > 5% of total plan contributions | Yes | Yes | Yes |
| No | No | No |
1A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006.
2The CEO is the only participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through July 17, 2016.
3The 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.
4The 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 the years ending December 31, 2015, 2014, and 2013 were $4.5 million, $4.5 million, and $4.1 million, respectively.
72
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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 the years ended December 31, 2015, 2014, and 2013 totaled $2.6 million, $2.9 million, and $2.9 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, 2015, 2014 and 2013 were $133.6 thousand, $149.2 thousand and $147.9 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, $17,500 and $17,500 in 2015, 2014 and 2013 respectively, and allowed catch-up contributions for those over 50 years of age of $6,000 in 2015 and $5,500 in 2014 and 2013. 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, 2015, 2014 and 2013 was $763,913, $666,967 and $536,546, 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.
73
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
(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 $21.6 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 $5.7 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 State of Alaska provided an initial grant for work on a project to divert water from Battle Creek into Bradley Lake. The project is being managed by the Alaska Energy Authority. Based on stream flow measurements from 1991 through 1993, diverting a portion of Battle Creek into Bradley Lake has the potential to increase annual energy output up to 40,000 megawatt-hours (MWh). Chugach would be entitled to 30.4% of the additional energy produced.
The following represents information with respect to Bradley Lake at June 30, 2015 (the most recent date for which information is available). Chugach's share of expenses was $5,663,304 in 2015, $5,228,907 in 2014, and $4,882,163 in 2013 and is included in purchased power in the accompanying financial statements.
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(In thousands) | Total |
| Proportionate Share | ||
Plant in service | $ | 167,235 |
| $ | 50,839 |
Long-term debt |
| 62,585 |
|
| 19,026 |
Interest expense |
| 3,668 |
|
| 1,115 |
Chugach's share of a Bradley Lake transmission line financed internally is included in Intangible Electric Plant.
74
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
(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 2015 included $4,401,440, net of accumulated depreciation of $2,203,659, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2014, plant in service included $4,442,440, net of accumulated depreciation of $2,017,032. 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. Under net billing arrangements, Chugach then reimburses MEA for their share of the costs. Chugach’s share of expenses was $689,501, $761,613, and $730,122 in 2015, 2014, and 2013, 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.
(15) 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, 2015, 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 an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA’s have been renewed through June 30, 2017. The HERE contract has been renewed through June 30, 2016.
Chugach was the principal supplier of power under wholesale power contracts with MEA and HEA, which expired April 30, 2015, and December 31, 2013, respectively. The MEA contract, including the fuel component, represented $26.2 million through its expiration, or 13% of 2015 sales revenue, and $70.7 million, or 26% of 2014 sales revenue. The MEA and HEA contracts, including the fuel component, represented $103.1 million, or 35% of 2013 sales revenue. All rates were established by the RCA.
75
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Fuel Supply Contracts
Chugach has fuel supply contracts from various producers at market terms. A gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “ConocoPhillips”), approved effective by the RCA on August 21, 2009, began providing gas in 2010 and will terminate December 31, 2016. The total amount of gas under the contract is currently estimated to be 60 Bcf. 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 2015, 86% of our power was generated from gas, with 30% generated at the Beluga Power Plant and 61% generated at SPP. In 2014 and 2013, 87% of our power was generated from gas, with 57% and 47%, respectively, generated at Beluga, and 43% and 31%, respectively, generated at SPP.
The terms of the ConocoPhillips and Hilcorp agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems. We have gas transportation agreements with ENSTAR and Hilcorp. 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:
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| 2015 |
| 2014 |
| 2013 | |||
Hilcorp | 30.3 | % |
| 50.4 | % |
| 46.4 | % |
ConocoPhillips (COP) | 58.7 | % |
| 43.6 | % |
| 42.8 | % |
AIX Energy | 4.7 | % |
| 0.0 | % |
| 0.0 | % |
ENSTAR | 3.3 | % |
| 2.0 | % |
| 2.1 | % |
Harvest (Hilcorp) Pipeline | 1.6 | % |
| 3.0 | % |
| 3.8 | % |
Miscellaneous | 1.4 | % |
| 1.0 | % |
| 4.9 | % |
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. HEA’s patronage capital payable was $7.9 million at December 31, 2015 and 2014. MEA’s patronage capital payable was $3.2 million and $2.3 million at December 31, 2015 and 2014, respectively.
76
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
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 $0.000732, effective July 1, 2015. 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 revenue tax in lieu of state and local ad valorem, income and excise taxes on electricity sold in the retail market. The tax is accrued monthly and remitted annually.
Production Taxes
Production taxes on Chugach fuel purchases are paid directly to our gas producers and are recorded under “Fuel” in Chugach’s financial statements.
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 $5,184,551 and $2,761,921 for this charge at December 31, 2015 and 2014, respectively. 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 are increasing from the original “TP1” levels to the new “DOE-2016” levels. The Energy Act mandates specific types of low voltage dry-type transformers manufactured and sold in the USA to have efficiencies as defined by the 10 CFR Part 431 standard when loaded to 35% of maximum capacity. Chugach is in the process of evaluating our transformer specifications and
77
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
will make modifications as necessary with our alliance transformer manufacturers to ensure DOE-2016 is met. 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 (CO2) 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 CO2 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. 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.
Economy Energy Sales
On October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015. Sales were made under the terms and conditions of Chugach’s economy energy sales tariff. The price to GVEA included the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin. Chugach had also entered into specific gas supply arrangements to make economy energy sales to GVEA. Sales revenue to GVEA amounted to $8.0 million in 2015 through the expiration of their contract, and $36.9 million in 2014.
78
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
Cooper Lake Hydroelectric Project
The Cooper Lake Hydroelectric Project received a 50-year license from FERC in August of 2007. A condition of that license is a requirement to construct a Stetson Creek diversion structure, a pipeline to Cooper Lake, and a bypass structure to release warmer water from Cooper Lake into Cooper Creek. If the project was not feasible or if the cost estimate materially exceeded the terms of the license, Chugach had the option to request a license amendment. At the time the project was being relicensed the estimated cost to complete the project was $12.0 million. Due to a change in FERC requirements, the completed project cost $22.2 million. As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska. Funding for this project included $9.3 million in grants awarded. The Chugach Board authorized expenditures for the project November 15, 2012. The diversion project began construction in 2013 and was put into service on July 25, 2015. It will operate through the duration of the license.
(16) Gain on Sale of Asset
On July 12, 2011, Chugach sold the Bernice Lake Power Plant to AEEC and HEA. Chugach recognized the proceeds from this sale as a liability on its Balance Sheet and continued to dispatch the power plant until the expiration of its power sales agreement with HEA. In December of 2013, Chugach recognized the gain associated with this sale which amounted to $6.4 million.
(17) Subsequent Events
Beluga River Unit
On February 4, 2016, Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” The Purchase and Sale Agreement transfers COP’s working interest in the BRU to Chugach and ML&P. The total purchase price is $152 million, with Chugach’s portion totaling $45.6 million.
Under the joint bid arrangement, Chugach’s ownership of COP’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 COP’s 67% working interest in deep oil resources. The acquisition is subject to the approval of the RCA (see “Note 5 – Regulatory Matters – Beluga River Unit”).
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 at an effective annual cost that is $2 million to $3 million less than alternative sources of gas in the Cook Inlet region. Approximately 80% of Chugach’s current generation requirements are met from natural gas, 16% are met from hydroelectric, and 4% are met from wind.
79
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2015 and 2014
The acquisition is expected to provide gas to meet Chugach’s on-going generation requirements over an approximate 18-year period, or from 2016 to 2033. Gas associated with the acquisition is expected to provide about 15% of Chugach’s gas requirements through 2033, although actual gas quantities produced are expected to vary on a year-by-year basis.
Chugach has firm gas supply contracts with COP and Hilcorp, as discussed in “Note 15 – Commitments and Contingencies – Fuel Supply Contracts”. In addition to Chugach, COP has contractual gas sales obligations to ENSTAR through 2017. These contracts are expected to be assumed by ML&P and Chugach on the basis of ownership share. In addition to these firm contracts, Chugach has gas supply agreements with Aurora Gas LLC through September 30, 2016, AIX Energy LLC through March 31, 2024 (with an option to extend the term an additional 5-year period through March 31, 2029), and with Cook Inlet Energy LLC through March 31, 2018 (with an option to extend the term an additional 5-year period through March 31, 2023). Collectively, these agreements provide added diversification and optionality for Chugach to minimize costs within its gas supply portfolio.
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. Currently, the BRU is jointly owned (one-third) by COP, Hilcorp, and ML&P. If the transaction is approved, ML&P’s ownership of the BRU would increase to approximately 56.7%, Hilcorp’s ownership would remain unchanged at 33.3%, and Chugach’s ownership would be 10.0%.
(18) Quarterly Results of Operations (unaudited)
2015 Quarter Ended
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| Dec. 31 |
| Sept. 30 |
| June 30 |
| March 31 | ||||
Operating Revenue | $ | 50,640,703 |
| $ | 43,109,512 |
| $ | 47,697,820 |
| $ | 74,973,117 |
Operating Expense |
| 42,182,178 |
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| 39,667,546 |
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| 43,490,558 |
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| 63,451,276 |
Net Interest |
| 5,415,131 |
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| 5,428,774 |
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| 5,381,167 |
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| 5,589,373 |
Net Operating Margins |
| 3,043,394 |
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| (1,986,808) |
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| (1,173,905) |
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| 5,932,468 |
Nonoperating Margins |
| 368,403 |
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| 79,028 |
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| 126,010 |
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| 114,262 |
Assignable Margins | $ | 3,411,797 |
| $ | (1,907,780) |
| $ | (1,047,895) |
| $ | 6,046,730 |
2014 Quarter Ended
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| Dec. 31 |
| Sept. 30 |
| June 30 |
| March 31 | ||||
Operating Revenue | $ | 69,272,422 |
| $ | 65,677,900 |
| $ | 70,269,305 |
| $ | 76,098,886 |
Operating Expense |
| 58,795,411 |
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| 61,712,934 |
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| 66,997,011 |
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| 65,467,523 |
Net Interest |
| 5,673,940 |
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| 5,622,892 |
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| 5,661,316 |
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| 5,842,558 |
Net Operating Margins |
| 4,803,071 |
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| (1,657,926) |
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| (2,389,022) |
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| 4,788,805 |
Nonoperating Margins |
| 411,590 |
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| 96,181 |
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| 249,820 |
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| 213,026 |
Assignable Margins | $ | 5,214,661 |
| $ | (1,561,745) |
| $ | (2,139,202) |
| $ | 5,001,831 |
80
Item 9 – Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None
Item 9A – Controls and Procedures
Evaluation of Controls and Procedures
As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rule 13a-15(e)) under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO). Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be disclosed in our periodic reports to the SEC, ensures that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding required disclosure. The design of any system of controls is based in part upon various assumptions about the likelihood of future events, and there can be no assurance that any of our plans, products, services or procedures will succeed in achieving their intended goals under future conditions. In addition, there were no changes in Chugach’s internal controls over financial reporting identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially affect, Chugach’s internal controls over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal controls over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Under the supervision and with the participation of our management, including our CEO and CFO, we assessed the effectiveness of our internal controls over financial reporting as of December 31, 2015, using the criteria set forth in “Internal Control Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (2013 framework). Based on this assessment, management believes that, as of December 31, 2015, Chugach maintained effective internal controls over financial reporting. In addition, there were no changes in Chugach’s internal controls over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act) identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably like to materially affect, Chugach’s internal controls over financial reporting.
81
As previously disclosed in the Chugach’s Current Report on Form 8-K dated February 25, 2016. The Board acknowledged the retirement of Chugach’s current CEO, Bradley W. Evans, effective July 17, 2016. Mr. Evans’ retirement is not due to any disagreement between Mr. Evans and Chugach on any matter relating to Chugach’s operations, policies, or practices. On February 25, 2016, the Board also appointed Lee D. Thibert, 60, to serve as Chugach’s CEO effective July 17, 2016.
Mr. Thibert has no family relationships with any current director, director nominee, or executive officer of Chugach, and there are no transactions or proposed transactions, to which Chugach is a party, or intended to be a party, in which Mr. Thibert has, or will have, a material interest subject to disclosure under Item 404(a) of Regulation S-K.
Mr. Thibert was not appointed as the CEO of Chugach pursuant to any arrangement or understanding with any other parties.
Item 10 – Directors, Executive Officers and Corporate Governance
Chugach operates under the direction of a Board of Directors (Board) that is elected at large by our membership. Day-to-day business and affairs are administered by the CEO. Our seven-member Board sets policy and provides direction to the CEO. Each statutory officer must be a member of the Board, but these officers do not participate in the day-to-day management of Chugach. No member of the Board is an employee of Chugach nor does any member of the Board have a material relationship with Chugach. Therefore, the Board has determined that all members are independent. Our Board of Directors oversees Chugach’s risk management, satisfying itself that our risk management practices are consistent with our corporate strategy.
Identification of Directors
Candidates for our Board of Directors may be nominated by a Nominating Committee or by petition. The Nominating Committee is comprised of members selected from different sections of the service area of Chugach. No member of the Board may serve on the Nominating Committee. The Nominating Committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting. Any 50 or more members, acting together, may make other nominations by petition.
As required by our bylaws, all of the members of our Board are elected solely by the vote of our members. We do not have any direct role in the nomination of the candidates or the election of members to our Board. Therefore, the following director biographies do not include a discussion of the specific experience, qualifications, attributes or skills that led our members to the conclusion that a person should serve as a director on our Board.
Janet Reiser, 60, Chair, was elected to the Board in 2008, and re-elected in 2011 and 2014. She currently serves on the Audit and Finance, Governance, and Operations Committees and is currently the Alaska Railbelt Cooperative Transmission & Electric Company (ARCTEC) representative. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned her Board Leadership Certificate. Her term expires in May of 2018.
82
Susan Reeves, 67, Vice Chair, is the managing member of Reeves Amodio LLC, where she practices law. She has been active on Alaska non-profit boards and commissions for many years. She was elected to the Board in 2010 and re-elected in 2013. She currently serves as the Chair of the Governance Committee and as a member of the Operations Committee. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director. Her term expires in May of 2016.
Bruce Dougherty, 56, Secretary, is retired from the State of Alaska having served for 24 years in a variety of positions in health and social service programs and a retired Lieutenant Colonel with the US Air Force Reserves. He has extensive experience in the field of health care, serving at various levels in senior care, disease intervention, and disability adjudication. He was appointed to the Board on March 17, 2015, and elected by the membership on May 14, 2015. He currently serves as a member of the Governance and Operations Committees. His term expires in May of 2016.
Sisi Cooper, 35, Treasurer, is a project engineer with Doyon Anvil, LLC. She specializes in process safety and risk management, energy-sector project management, and process/facility engineering and design. Sisi is a former small business owner of North Ridge Home Inspections, LLC where she was the principal inspector. She is a NRECA Credentialed Cooperative Director. She was elected to the Board in 2012 and re-elected in 2015. She currently serves as the Chair of the Audit and Finance Committee and as a member of the Governance Committee. Her term expires in May of 2019.
Bettina Chastain, 51, Director, is an executive, business owner and engineer who has spent her career providing technical and management consulting services to the oil and gas and energy sectors in Alaska, nationally and internationally. She was elected to the Board in May of 2015. She currently serves as Vice Chair of the Operations Committee and as a member of the Audit and Finance Committee. Her term expires in May of 2019.
Harry T. Crawford, Jr., 63, Director, is a former Alaska State Legislator, retired iron worker and a small real estate developer. He was elected to the Board in 2011 and re-elected in 2014. He currently serves as Chair of the Operations Committee and as a member of the Audit and Finance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2017.
Jim Henderson, 69, Director, is a principal with New American Financial Group in the financial services industry. He specializes in asset-based finance products, reorganization and refinancing of distressed companies, and accounting and disposition of capital assets. His primary emphasis is transportation, industrial machinery and aviation operations, assets and industry development. He has over 35 years of experience in consulting and analysis and finance of capital assets. Mr. Henderson has served on various committees for Chugach in the past. He was elected to the Board in 2011 and re-elected in 2014. He currently serves as the Vice Chair of the Audit and Finance Committee and as a member of the Governance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2018.
83
Identification of Executive Officers
Bradley W. Evans, 61, was appointed Chief Executive Officer on July 1, 2008. Prior to that appointment, Mr. Evans served as Interim CEO since December 5, 2007. Prior to that appointment, he served as Sr. Vice President, Power Supply since March 20, 2006, General Manager, G&T Division since January 31, 2005, Sr. Vice President, Energy Supply since June 5, 2002, and Director, Energy Supply since February 26, 2001. Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association.
Sherri Highers, 47, was appointed Chief Financial Officer and Vice President, Finance and Administration effective July 23, 2013. Prior to this appointment, Ms. Highers was serving as Manager, Budget and Financial Reporting, guiding Chugach’s financial planning and reporting responsibilities. Ms. Highers has worked at Chugach for approximately 18 years and has held various accounting management positions.
Paul R. Risse, 61, was appointed Sr. Vice President, Power Supply on October 27, 2008. Prior to that appointment, he served as Acting Sr. Vice President, Power Supply since December 6, 2007. Prior to that appointment, Mr. Risse served as Director of Generation Technical Services since March 27, 2006; Manager, Plant Technical Services since January 1, 2003; Project Manager since August 15, 2000; Project Engineer since April 5, 2000; and Manager Substation Operations since January 25, 1995. Prior to his current Chugach employment, Mr. Risse served in various Transmission and Generation positions at Southern California Edison.
Lee D. Thibert, 60, was appointed Sr. Vice President, Strategic Development and Regulatory Affairs on July 1, 2013. Prior to that appointment he served as Sr. Vice President, Strategic Planning and Corporate Affairs since June 11, 2008, Sr. Vice President, Power Delivery from March 20, 2006, to February 1, 2008, General Manager, Distribution Division since January 31, 2005, Sr. Vice President, Power Delivery since June 3, 2002, Executive Manager, Transmission & Distribution Network Services since June 1, 1997, Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May of 1987.
Tyler E. Andrews, 50, was appointed Vice President, Member and Employee Services on September 9, 2013. Prior to that appointment he served as Vice President, Human Resources since March 17, 2008. Mr. Andrews has over 20 years of experience in Human Resources and Labor Relations. Since June of 2008, Mr. Andrews has also served as an appointed board member of the State of Alaska’s labor relations agency. Prior to his employment with Chugach, Mr. Andrews served as the Sr. Manager of Labor Relations for Alaska Communications Systems. Prior to that, he served more than 10 years with the State of Alaska in a wide range of Human Resources and Labor Relations functions including Human Resources Manager and Chief Spokesperson on numerous collective bargaining teams.
William J. Bernier, 68, was appointed Vice President, Power Delivery on November 4, 2014. Prior to that appointment he served as Acting Vice President, Power Delivery since June 9, 2014, and Director, Substations and Line Operations since August 30, 1999. Mr. Bernier has more than 45 years of experience in the Transmission, Distribution and Substation field. Prior to his employment at Chugach, Mr. Bernier served in various management positions at Alcan Electrical & Engineering, Inc., Norcon, Inc., New England Power Service Company, and Commonwealth Electric Company, Inc.
84
Code of Ethics
Chugach finalized a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions on June 16, 2004. In February of 2009, Chugach contracted with an outside firm to provide a financial reporting hotline to support the code of ethics. It is also posted on Chugach’s website at www.chugachelectric.com.
Nominating Committee
Chugach has not made any material changes to the procedures by which our membership may recommend nominees to our Board. The Board appoints a Nominating Committee each year. The Nominating Committee consists of members selected from different sections of the service area of Chugach. No member of the Board may serve on the Nominating Committee. The Nominating Committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting. The Nominating Committee considers diversity, skills, and such other factors as it deems appropriate given the current needs of the Board and Chugach. Any 50 or more members, acting together, may make other nominations by petition. Six of our current Board members were nominated by the Nominating Committee and one was nominated by petition.
Audit and Finance Committee Financial Expert
The Board relies on the advice of all members of the Audit and Finance Committee therefore the Board has not formally designated an Audit and Finance Committee financial expert.
Identification of the Audit and Finance Committee
Chugach Board Policy No. 127, “Audit and Finance Committee Charter,” defines the Audit and Finance Committee as follows:
The Audit and Finance Committee shall be comprised of three or more directors as determined by the Board. Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Association or an outside consultant or other programs. The Committee may also retain the services of a qualified accounting professional with auditing expertise to assist it in the performance of its responsibilities.
The Board Chair shall appoint the Board Treasurer as Audit and Finance Committee Chairperson. The Audit and Finance Committee shall elect from its members a Vice Chair, and appoint a recording secretary as needed. Members of the 2015 Audit and Finance Committee include Chair Sisi Cooper, Vice Chair Jim Henderson and Directors Bettina Chastain, Harry Crawford, and Janet Reiser.
The disclosure required by Rule 10A-3(d) of the Exchange Act regarding exemption from the listing standards for audit committees is not applicable to the Chugach Audit and Finance Committee.
85
Item 11 – Executive Compensation
Compensation Discussion and Analysis
In 1986, the NRECA developed the COMPensate wage and salary plan to provide its members with a systematic and standardized method to evaluate jobs in their specific cooperative, grade them, compare wages and salaries with those in similar electric utility systems and in the external marketplace and then create and apply statistically determined, equitable pay scales. In 1988, the Chugach Board approved implementation of NRECA’s COMPensate wage and salary plan for non-bargaining unit employees with the objective of establishing wages and salaries for non-bargaining unit employees that would attract and retain qualified personnel and encourage their superior performance, growth and development.
Each year the regression analysis/compensation model is updated with current salary survey values to ensure that the ranges reflect fair market value. The overall change to the salary ranges reflects market changes to the midpoint of the salary ranges and creates an opportunity for but not a guarantee of salary increases. Salary increases are not automatic and are based on performance. Any changes to the salary plan for Chugach are approved by the Chugach Board.
Compensation Committee Interlocks and Insider Participation
Chugach does not have a compensation committee. The compensation of the CEO is determined by the Board and no other individual, whether presently or previously employed by Chugach, was a party to the deliberations undergone by the Board in determining the CEO’s compensation.
CEO Brad Evans is eligible for performance-based bonuses at the discretion of the Board based on performance objectives and incentive-based bonuses to a maximum of $50,000. On January 4, 2012, the Board adopted a CEO Incentive Program to provide additional bonus opportunities to the CEO outside of the annual CEO performance review. The program sets goals, with specified criteria to be achieved during each calendar year. Each category of goals - fuel security, financial performance, safety, reliability, renewable energy long range plan, job approval and renewable energy integration - is allocated a percentage of a total bonus amount to a maximum of $50,000. In 2015, 2014 and 2013, upon review of the performance of the CEO, Mr. Evans received bonuses of $98,000, $95,000 and $45,000, respectively.
The median employee was determined as of December 31, 2015, and the total annual compensation of Chugach’s median employee was $240,053. The CEO’s total compensation in 2015 was 2.54 times the total compensation of Chugach’s median employee.
Chugach does not have shareholders and no vote has been put before the membership to approve the CEO’s compensation or the compensation of any other named executive. The salary and bonuses for all other named executive officers are set annually by the CEO within annual budget guidelines approved by the Board.
Compensation Committee Report
The Board has reviewed and discussed the disclosures included in the Compensation Discussion and Analysis with management and has recommended the disclosures be included in Chugach’s Annual Report on Form 10-K.
86
Cash Compensation
The following table sets forth all remuneration paid by us for the last three fiscal years to each of our executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2015 and for all such executive officers as a group:
Summary Compensation Table
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Name |
| Year |
| Salary |
| Bonus |
| Change in Pension Value and Nonqualified Deferred Compensation |
| All Other Compensation 1 |
| Total | |||||
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Bradley W. Evans, |
| 2015 |
| $ | 336,057 |
| $ | 98,000 |
| $ | 167,171 |
| $ | 7,808 |
| $ | 609,036 |
Chief Executive Officer |
| 2014 |
| $ | 314,284 |
| $ | 95,000 |
| $ | 132,305 |
| $ | 7,193 |
| $ | 548,782 |
|
| 2013 |
| $ | 305,192 |
| $ | 45,000 |
| $ | 248,897 |
| $ | 4,542 |
| $ | 603,631 |
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Sherri L. Highers, |
| 2015 |
| $ | 175,692 |
| $ | 12,500 |
| $ | 66,509 |
| $ | 25,165 |
| $ | 279,866 |
Chief Financial Officer |
| 2014 |
| $ | 154,275 |
| $ | 7,000 |
| $ | 37,000 |
| $ | 4,214 |
| $ | 202,489 |
|
| 2013 |
| $ | 118,088 |
| $ | 4,000 |
| $ | 7,830 |
| $ | 2,607 |
| $ | 132,525 |
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Paul R. Risse |
| 2015 |
| $ | 215,447 |
| $ | 16,000 |
| $ | 114,127 |
| $ | 12,595 |
| $ | 358,169 |
Sr. Vice President, |
| 2014 |
| $ | 202,298 |
| $ | 15,000 |
| $ | 96,615 |
| $ | 11,748 |
| $ | 325,661 |
Power Supply |
| 2013 |
| $ | 187,960 |
| $ | 20,000 |
| $ | 152,114 |
| $ | 12,389 |
| $ | 372,463 |
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Lee D. Thibert, |
| 2015 |
| $ | 247,266 |
| $ | 27,000 |
| $ | 148,951 |
| $ | 18,888 |
| $ | 442,105 |
Sr. Vice President, Strategic |
| 2014 |
| $ | 232,252 |
| $ | 15,000 |
| $ | 126,569 |
| $ | 10,648 |
| $ | 384,469 |
Development & Regulatory Affairs |
| 2013 |
| $ | 214,773 |
| $ | 12,500 |
| $ | 153,767 |
| $ | 9,120 |
| $ | 390,160 |
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Tyler E. Andrews, |
| 2015 |
| $ | 181,744 |
| $ | 14,500 |
| $ | 37,243 |
| $ | 34,169 |
| $ | 267,656 |
Vice President, |
| 2014 |
| $ | 171,088 |
| $ | 8,000 |
| $ | 28,300 |
| $ | 4,785 |
| $ | 212,173 |
Member and Employee Services |
| 2013 |
| $ | 158,777 |
| $ | 10,000 |
| $ | 29,760 |
| $ | 5,692 |
| $ | 204,229 |
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William J. Bernier, |
| 2015 |
| $ | 184,740 |
| $ | 10,500 |
| $ | 54,284 |
| $ | 12,899 |
| $ | 262,423 |
Vice President, |
| 2014 |
| $ | 166,913 |
| $ | 1,000 |
| $ | 50,174 |
| $ | 8,682 |
| $ | 226,769 |
Power Delivery |
| 2013 |
| $ | 147,887 |
| $ | 0 |
| $ | 44,853 |
| $ | 6,481 |
| $ | 199,221 |
1Includes costs for life insurance premiums, tax withholdings on bonuses, payment for unused vacation days and non-cash awards.
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Pension Benefits
We have elected to participate in the NRECA RS Plan, a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. Under ASC 960, “Topic 960 – Plan Accounting – Defined Benefit Pension Plans,” the plan is a multi- employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. The RS Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All employees not covered by a union agreement become participants in the RS Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first 12 consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10% for each of the first four years of vesting service and become fully vested and non-forfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age 55 while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he or she performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant's retirement or death. A participant may also elect to receive pension benefits while still employed by us if he or she has reached his normal retirement date by completing 30 years of benefit service (defined below) or, if earlier, by attaining age 62. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she has attained age 55.
Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant. Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant's surviving spouse will receive pension benefits for life equal to 50% of the participant's benefit. The annual amount of a participant's pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his or her years of participation in the RS Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last 10 years of his or her participation in the RS Plan (final average salary). Annual compensation in excess of $265,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant's annual pension benefit at his or her normal retirement date is equal to the product of his or her years of benefit service times final average salary times two percent. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA's Retirement and Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May of 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.
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On October 16, 2002, the Board authorized an amendment to the RS Plan with an effective date of November 1, 2002. Under the amended RS Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall be computed as of the Participant’s actual retirement date. The retirement benefit payable to any Participant under the 30-Year RS Plan shall be computed as of the first day of the month in which the Participant’s actual retirement date occurs.
Benefit service as of December 31, 2015 that is taken into account under the RS Plan for the executive officers is shown below with the assumptions for calculation of the present value of accumulated benefits.
Pension Benefits Table
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Name |
| Plan |
| Credited |
| Present Value of Accumulated Benefit |
| NRECA RS | ||
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Bradley W. Evans, |
| Retirement Security |
| 14.83 |
| $ | 1,285,732 |
| $ | 0 |
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| Pension Restoration |
| 14.83 |
| $ | 209,373 |
| $ | 0 |
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Sherri L. Highers, Chief Financial Officer |
| Retirement Security |
| 16.08 |
| $ | 309,074 |
| $ | 0 |
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Paul R. Risse, |
| Retirement Security |
| 19.92 |
| $ | 1,225,150 |
| $ | 0 |
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Lee D. Thibert, Sr. VP, Strategic Development & Regulatory Affairs |
| Retirement Security |
| 27.33 |
| $ | 1,875,777 |
| $ | 0 |
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Tyler E. Andrews, |
| Retirement Security |
| 6.75 |
| $ | 224,680 |
| $ | 0 |
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William J. Bernier, |
| Retirement Security |
| 6.42 |
| $ | 291,289 |
| $ | 0 |
It is assumed that participants retire at the earlier of age 62 or 30 years of benefit service and elect a lump sum benefit.
Lump sum amounts are calculated using the PGGC rate (1.00% for 2015 and 1.75% for 2014), 30-year Treasury rate (3.04% for 2015 and 3.80% for 2014) and the Pension Protection Act (PPA) three-segment yield rates (1.40%, 3.88%, and 4.96% for 2015 and 1.19%, 4.53%, and 5.66% for 2014) and the required IRS mortality table for lump sum payments (1994 Guaranteed Annuity Rate (GAR), projected to 2002, blended 50%/50% for unisex mortality in combination with the 30-year Treasury rates and Retirement Plan (RP) 2000 PPA at 2015 and 2014, respectively, combined unisex 50%/50% mortality in combination with the PPA rates). The lump sum is then discounted at 4.22% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2015, and 3.80% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2014, to determine the present value for the
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appropriate year.
Deferred Compensation
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. As a non-qualified plan under Internal Revenue Code 457(b), the Deferred Compensation Plan is not subject to non-discrimination testing. The Program is designed to help decrease current taxable income, take advantage of tax deferred compounding and set aside additional money for retirement. The money is accessible only upon separation of service, disability or death (in which case it is paid to the designated beneficiary). The distribution is taxable as income in the year received.
Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made. Deferred compensation plan assets would be subject to creditors’ demands in the case of bankruptcy. Deferred compensation assets are invested with Vanguard Funds, a family of no-load mutual funds. Each participant in the Program determines the investment fund or funds into which their accounts are invested. The amounts credited to the deferred compensation account, including gains and 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.
Deferred Compensation Table
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Name |
| Executive Contributions in last FY |
| Registrant Contributions in last FY |
| Aggregate Change in last FY |
| Aggregate Withdrawals/ Distributions |
| Aggregate balance at FYE | |||||
Bradley W. Evans, |
| $ | 18,000 |
| $ | 0 |
| $ | 69 |
| $ | 0 |
| $ | 143,547 |
Chief Executive Officer |
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Tyler E. Andrews, |
| $ | 18,000 |
| $ | 0 |
| $ | (2,002) |
| $ | 0 |
| $ | 68,398 |
Vice President, Member and |
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Employee Services |
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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. If Mr. Evans is terminated by Chugach without cause, he will receive a lump sum payment equal to 50% of his annual Base Salary payable within 90 days, and the full cost of health and welfare coverage for a period not in excess of six months.
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The following is a list of the estimated severance payments, including the payment of accrued vacation that would be made to each of the executive officers in the case of termination not related to employee performance:
Potential Termination Payments Table
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Name |
| Estimated Severance Payment | |
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Bradley W. Evans, |
| $ | 317,915 |
Chief Executive Officer |
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Sherri L. Highers, |
| $ | 115,168 |
Chief Financial Officer |
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Paul R. Risse, |
| $ | 258,618 |
Sr. Vice President, Power Supply |
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Lee D. Thibert, |
| $ | 175,258 |
Sr. Vice President, Strategic Development |
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& Regulatory Affairs |
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Tyler E. Andrews, |
| $ | 83,658 |
Vice President, Member and Employee |
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Services |
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William J. Bernier, |
| $ | 94,668 |
Vice President, Power Delivery |
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Director Compensation
Directors are compensated for their services at the rate of $300 per Board meeting and $200 per other meeting at which they are representing Chugach in an official capacity within the State of Alaska, and $350 per day when attending meetings or training outside of the State, including a fee for each day of travel, plus reimbursement of reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chair. The Chair of the Board receives an additional $50 per day for each day of each meeting if the Chair performs the duties of Chair at the meeting.
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The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2015, to each of our current and former Board members:
Director Compensation Table
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Name |
| Fees Paid In Cash | |
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Janet Reiser, Chair and Director |
| $ | 24,200 |
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Susan Reeves, Vice-Chair and Director |
| $ | 13,300 |
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Bruce Dougherty, Secretary and Director |
| $ | 11,350 |
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Sisi Cooper, Treasurer and Director |
| $ | 15,100 |
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Bettina Chastain, Director |
| $ | 8,200 |
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Harry Crawford, Jr., Director |
| $ | 17,300 |
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Jim Henderson, Director |
| $ | 15,700 |
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David Gillespie, Former Director |
| $ | 1,600 |
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James Nordlund, Former Director |
| $ | 2,600 |
One Board member was re-elected, one appointed Board member was elected and one new Board member was elected at Chugach’s annual membership meeting held on May 14, 2015. Sisi Cooper and Bettina Chastain were elected to four year terms and Bruce Dougherty was elected to a one year term.
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Not Applicable
Item 13 – Certain Relationships and Related Transactions, and Director Independence
Not Applicable
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Item 14 – Principal Accounting Fees and Services
The Audit and Finance Committee of the Board retained KPMG LLP as the independent registered public accounting firm for Chugach during the fiscal year ended December 31, 2015.
Fees and Services
KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows:
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| 2015 |
| 2014 | ||
Audit and audit-related services: |
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Audit and quarterly reviews |
| $ | 169,840 |
| $ | 181,975 |
Audit-related services |
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| 36,555 |
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| 36,105 |
Non-audit services: |
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Tax consulting and return preparation |
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| 10,200 |
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| 10,350 |
Other services |
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| 0 |
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| 0 |
Total |
| $ | 216,595 |
| $ | 228,430 |
The Audit and Finance Committee has a policy to pre-approve all services to be provided by Chugach’s independent public accountants. All services from Chugach’s independent registered public accounting firm for fiscal years ended December 31, 2015 and 2014 were approved by the Audit and Finance Committee.
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Item 15 – Exhibits, Financial Statement Schedules
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| Page |
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Financial Statements |
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Included in Part II of this Report |
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Report of Independent Registered Public Accounting Firm | 41 |
Balance Sheets, December 31, 2015 and 2014 | 42-43 |
Statements of Operations |
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Years ended December 31, 2015, 2014 and 2013 | 44 |
Statements of Changes in Equities and Margins |
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Years ended December 31, 2015, 2014 and 2013 | 45 |
Statements of Cash Flows |
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Years ended December 31, 2015, 2014 and 2013 | 46 |
Notes to Financial Statements | 47-80 |
Other schedules are omitted as they are not required or are not applicable, or the required information is shown in the applicable financial statements or notes thereto.
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EXHIBITS
Listed below are the exhibits, which are filed as part of this Report:
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Exhibit Number |
Description
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3.1 | Articles of Incorporation of the Registrant. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001, SEC File No. 033-42125. |
3.2 | Bylaws of the Registrant. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 14, 2015, SEC File No. 033-42125. |
4.18 | Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 20, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. |
4.19 | First Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 20, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. |
4.20 | Bond Purchase Agreement between the Registrant and the 2011 Series A Bond Purchasers dated January 21, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. |
4.21 | Form of 2011 Series A Bond (Tranche A) due March 15, 2031. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. |
4.22 | Form of 2011 Series A Bond (Tranche B) due March 15, 2041. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. |
4.23 | Second Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated September 30, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
4.24 | Third Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 5, 2012. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
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4.25 | Bond Purchase Agreement between the Registrant and the 2012 Series A Bond Purchasers dated January 11, 2012. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
4.26 | Form of 2012 Series A Bond (Tranche A) due March 15, 2032. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
4.27 | Form of 2012 Series A Bond (Tranche B) due March 15, 2042. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
4.28 | Form of 2012 Series A Bond (Tranche C) due March 15, 2042. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
4.29 | Fourth Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated February 3, 2015. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated February 3, 2015, SEC File No. 033-42125. |
10.2 | Joint Use Agreement between the Registrant and the City of Seward dated effective as of September 11, 1998. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. |
10.3 | Net Billing Agreement among the Registrant and the City of Seward dated effective as of September 11, 1998. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125. |
10.4.2 | 2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective February 27, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125. |
10.4.3 | Amendment No. 2 to the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective March 1, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2012, SEC File No. 033-42125. |
10.7 | Power Purchase Agreement by and between Fire Island Wind, LLC and the Registrant dated as of June 21, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. |
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10.15.1 | Amended and Restated Alaska Intertie Agreement Among Alaska Energy Authority, Municipality of Anchorage d/b/a Municipal Light and Power, the Registrant, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc. dated November 18, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. | ||
10.17 | Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
10.18 | Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400. | ||
10.19 | Intertie Grant Agreement between the Registrant, Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and Homer Electric Association, Inc.), City of Seward, the State of Alaska, Department of Administration and Alaska Industrial Development and Export Authority dated August 17, 1993. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125. | ||
| Grant Transfer and Delegation Agreement between the Registrant and Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer Electric Association, Inc., Seward, the State of Alaska, Department of Administration, and AMEA dated November 5, 1993. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125. | ||
10.22 | Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400. | ||
10.23 | Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400. |
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10.24 | Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
10.24.1 | Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125. | ||
10.25 | Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
| Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125. | ||
10.26 | Transmission Sharing Agreement by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
10.27 | Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. |
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10.28 | Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125. | ||
10.29 | Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125. | ||
10.29.1 | Assignment of Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125. | ||
10.30 | Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
10.30.1 | Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
10.30.2 | Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
10.31 | Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125. | ||
10.32 | Eklutna Purchase Agreement by and among the Registrant, Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power and Alaska Power Administration. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125. | ||
| Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. Previously reported as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997, SEC File No. 033-42125. |
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10.35 | FSS Service Agreement between Cook Inlet Natural Gas Storage Alaska, LLC and the Registrant, effective October 26, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125. | ||
10.36 | Agreement by and among the Registrant, Municipality of Anchorage d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association, Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service, Alaska Energy Authority and the State of Alaska re: the Eklutna and Snettisham Hydroelectric Projects. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125. | ||
10.37 | Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125. | ||
10.45.8 | Amended and Restated Master Loan Agreement between the Registrant and CoBank, ACB dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. | ||
10.45.9 | Second Amended and Restated Supplement between the Registrant and CoBank, ACB, dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. | ||
10.45.10 | Form of 2011 CoBank Note dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. | ||
10.47.3 | Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 12, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2012, SEC File No. 033-42125. | ||
10.49 | 2010 Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125. | ||
10.49.1 | Amendment No. 1 to the Credit Agreement between the Registrant and NRUCFC dated effective June 29, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2012, SEC File No. 033-42125. |
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10.56 | Order On Offer Of Settlement And Issuing New License between the Registrant and the Federal Energy Regulatory Commission dated effective August 24, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125. | |
10.58 | Agreement Covering Terms and Conditions of Employment for Beluga Power Plant Culinary Employees between the Registrant and the Hotel Employees & Restaurant Employees Union Local 878 dated effective December 13, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125. | |
10.58.1 | Letter of Agreement By and Between the Registrant and the Hotel Employees and Restaurant Employees Union Local 878 dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2010, SEC File No. 033-42125. | |
10.58.2 | Letter of Agreement By and Between the Registrant and the Hotel Employees and Restaurant Employees Union Local 878 dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2013, SEC File No. 033-42125. | |
10.59 | Agreement Covering Terms and Conditions of Employment for Office and Engineering Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective September 13, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125. | |
10.59.1 | Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Office and Engineering Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125. | |
10.59.2 | Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Office and Engineering Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2013, SEC File No. 033-42125. | |
10.60 | Agreement Covering Terms and Conditions of Employment for Generation Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective November 9, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125. | |
10.60.1 | Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Generation Plant Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125. |
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10.60.2 | Letter Of Agreement between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated March 15, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2012, SEC File No. 033-42125. | |
10.60.3 | Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Generation Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2013, SEC File No. 033-42125. | |
10.61 | Agreement Covering Terms and Conditions of Employment for Outside Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective December 12, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125. | |
10.61.1 | Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Outside Plant Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125. | |
10.61.2 | Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Outside Plant Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2013, SEC File No. 033-42125. | |
10.64.2 | Employment Agreement between the Registrant and Bradley W. Evans dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 16, 2013, SEC File No. 033-42125. | |
10.65 | Agreement for the Sale and Purchase of Natural Gas between the Registrant and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively, ConocoPhillips) effective August 21, 2009. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 21, 2009, SEC File No. 033-42125. | |
10.66 | Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Alaska Production, LLC (MAP) effective May 17, 2010. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 17, 2010, SEC File No. 033-42125. | |
10.67 | Engineering, Procurement and Construction Contract between the Registrant and SNC-Lavalin Constructors, Inc. dated effective June 18, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2015, SEC File No. 033-42125. |
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10.68 | Transportation Agreement between the Registrant and Beluga Pipeline Company dated effective October 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125. | |
10.69 | Transportation Agreement For Interruptible Transportation Of Natural Gas between the Registrant and Kenai Nikiski Pipeline dated effective October 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125. | |
10.73 | Special Contract for Natural Gas Transportation Service between the Registrant and ENSTAR Natural Gas Company effective November 1, 2012. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125. | |
10.74 | Firm Transportation Service Agreement between the Registrant and ENSTAR Natural Gas Company effective August 1, 2012. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125. | |
10.75 | Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska LLC effective September 10, 2013. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated September 10, 2013, SEC File No. 033-42125. | |
10.75.1 | First Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective September 15, 2014. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2014, SEC File No. 033-42125. | |
10.75.2 | Second Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective May 4, 2015. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2015, SEC File No. 033-42125. | |
10.75.3 | Third Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective September 8, 2015. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2015, SEC File No. 033-42125. | |
10.76 | Agreement between the Registrant and Cook Inlet Energy Inc. effective December 2, 2013. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2013, SEC File No. 033-42125. | |
10.77 | 2015 Interim Power Sales Agreement between the Registrant and Matanuska Electric Association, Inc. effective December 31, 2014. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated December 22, 2014, SEC File No. 033-42125. |
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10.77.1 | Memorandum of Understanding Regarding 2015 Interim Power Sales Agreement and Eklutna Generation Station agreements between the Registrant and Matanuska Electric Association, Inc. effective March 31, 2015. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated March 31, 2015, SEC File No. 033-42125. | |
14 | Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004, SEC File No. 033-42125. | |
31.1 | Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2 | Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1 | Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2 | Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101.INS | XBRL Instance Document | |
101.SCH | XBRL Taxonomy Extension Schema Document | |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.LAB | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 23, 2016.
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| CHUGACH ELECTRIC ASSOCIATION, INC. |
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By: | /s/ Bradley W. Evans |
| Bradley W. Evans |
| Chief Executive Officer |
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Date: | March 23, 2016 |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 16, 2016, by the following persons on behalf of the registrant and in the capacities indicated:
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/s/ Bradley W. Evans |
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Bradley W. Evans |
| Chief Executive Officer |
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| (Principal Executive Officer) |
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/s/ Sherri L. Highers |
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Sherri L. Highers |
| Chief Financial Officer |
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| (Principal Financial Officer) |
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| (Principal Accounting Officer) |
/s/ Paul R. Risse |
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Paul R. Risse |
| Sr. Vice President, Power Supply |
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/s/ Lee D. Thibert |
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Lee D. Thibert |
| Sr. Vice President, Strategic Development & |
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| Regulatory Affairs |
/s/ William J. Bernier |
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William J. Bernier |
| Vice President, Power Delivery |
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/s/ Tyler E. Andrews |
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Tyler E. Andrews |
| Vice President, Member and Employee Services |
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/s/ Janet Reiser |
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Janet Reiser |
| Director & Chair of the Board |
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Susan Reeves |
| Director & Vice Chair of the Board |
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/s/ Sisi Cooper |
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Sisi Cooper |
| Director & Treasurer of the Board |
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Bruce Dougherty |
| Director & Secretary of the Board |
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Bettina Chastain |
| Director |
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/s/ Harry T. Crawford, Jr. |
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Harry T. Crawford, Jr. |
| Director |
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/s/ Jim Henderson |
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Jim Henderson |
| Director |
Supplemental Information to be Furnished With Reports Filed
Pursuant to Section 15(d) of the Act by Registrants
Which Have Not Registered Securities Pursuant to Section 12 of the Act
Chugach has not made an Annual Report to securities holders for 2015 and will not make such a report after the filing of this Form 10‑K. As a consequence, no copies of any such report will be furnished to the Securities and Exchange Commission.
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