Advertise with us
[November 01, 2012]
IDACORP INC - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Edgar Glimpses Via Acquire Media NewsEdge) (Megawatt-hours (MWh) and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.) INTRODUCTION In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power, and the notes thereto. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2011, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year.
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power. IDACORP's common stock is listed and trades on the New York Stock Exchange under the trading symbol "IDA." Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. Idaho Power provided electric service to approximately 500,000 general business customers as of September 30, 2012. As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), which determine the rates that Idaho Power charges to its general business customers. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its Federal Energy Regulatory Commission (FERC) tariff and to provide transmission services under its FERC open access transmission tariff (OATT). Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, and to seek to earn a return on investment.
Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity. Idaho Power's revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel. Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand. Idaho Power has implemented a tiered-rate structure and seasonal rates. Both mechanisms increase the rates customers pay during higher-usage periods based on the amount of usage and time of year and are premised on encouraging energy efficiency during higher-usage periods and reflect the higher cost of providing service in those periods. These rate structures also contribute to seasonal fluctuations in earnings and revenues.
IDACORP's and Idaho Power's financial condition are also affected by regulatory decisions, through which Idaho Power seeks to recover its costs on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.
IDACORP's other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy, a marketer of energy commodities, which wound down operations in 2003. Idaho Power is the parent of Idaho Energy Resources Co.
(IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
39-------------------------------------------------------------------------------- Table of Contents EXECUTIVE OVERVIEW Brief Overview of Third Quarter 2012 Financial Results IDACORP's earnings were $1.84 per diluted share for the quarter ended September 30, 2012, compared to $2.16 per diluted share for the same quarter in 2011. IDACORP's results in the third quarter of 2012 were positively impacted by general rate increases implemented during the year, but earnings for the quarter were lower than the third quarter of last year due to the financial statement impact of a tax method change recognized last year. These results, including a quantification of their respective impacts, are discussed in detail below.
Overview of General Factors and Trends Affecting Results of Operations and Financial Condition IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, economic, and other factors, many of which are described below.
Emphasis on Timely Regulatory Cost Recovery: The price that regulators authorize Idaho Power to charge for electric service is a major factor in determining IDACORP's and Idaho Power's results of operations and financial condition. Because of the significant impact of ratemaking decisions on Idaho Power's business and financial condition, the company continues to focus on timely recovery of its costs through filings with the company's regulators, including the IPUC, the OPUC, and the FERC. Effective implementation of Idaho Power's purposeful regulatory strategy is particularly important in an economic climate that puts more pressure on regulators to limit rate increases or otherwise take actions to limit the potential adverse impact of rate increases on customers, while at the same time the company requires rate increases to recover costs of providing reliable service. Particularly notable regulatory developments that have impacted or that IDACORP and Idaho Power expect will impact results, each of which is discussed in more detail under "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report, are listed below.
Additional important regulatory matters are also discussed in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.
Proceeding Description Status Idaho General Rate General rate case, requesting IPUC approved a $34.0 million Case Settlement an increase in increase in rates, effective Idaho-jurisdiction base rates January 1, 2012 Langley Gulch Request for recovery of and IPUC approved a $58.1 million Power Plant return on Idaho Power's increase in rates, effective investment in the Langley Gulch July 1, 2012; OPUC approved a power plant, including $3.0 million increase in rates operating costs effective October 1, 2012 Idaho Power Cost Annual Idaho-jurisdiction PCA IPUC approved a $43.0 million Adjustment (PCA) mechanism rate change increase in rates, effective only for the period from June 1, 2012 to May 31, 2013 (1) Revenue Sharing Rate adjustment pursuant to IPUC approved a $27.1 million January 2010 and December 2011 decrease in rates, effective settlement agreements(2) only for the period from June 1, 2012 to May 31, 2013(2)Idaho Depreciation Application for removal from IPUC approved a $10.6 million for Non-AMI Meters rates of accelerated decrease in rates and depreciation expense associated associated depreciation with non-advanced metering expense, effective June 1, infrastructure (AMI) metering 2012 equipment Oregon General General rate case, requesting OPUC approved a $1.8 million Rate Case an increase in increase in rates, effective Settlement Oregon-jurisdiction base rates March 1, 2012 (1) The rate change for the Idaho PCA was partially offset by the revenue-sharing order issued pursuant to the January 2010 and December 2011 settlement agreements.
(2) Idaho Power's revenue-sharing arrangements had two components: (a) a PCA mechanism component, which reduced net rates by $27.1 million, and (b) a pension balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction and $20.3 million pension regulatory asset reduction in 2011.
In addition to the rate changes listed in the table above, in December 2011 the IPUC approved a settlement stipulation, separate from the Idaho general rate case settlement, that permits Idaho Power to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent rate of return on year-end equity in the Idaho jurisdiction (Idaho 40-------------------------------------------------------------------------------- Table of Contents ROE) in 2012, 2013, and 2014, subject to prescribed limits and conditions. The settlement stipulation also provides for the potential sharing between the company and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. The specific terms of the settlement stipulation are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the years, IDACORP and Idaho Power believe the ability to amortize additional ADITC provides an element of earnings stability for the period from 2012 to 2014. Based on Idaho Power's estimate of full year 2012 Idaho ROE as of the date of this report, Idaho Power does not anticipate the need to amortize additional ADITC in 2012. Based on the terms of the December 2011 settlement stipulation, Idaho Power recorded during the third quarter of 2012 a $6.3 million provision against current revenues, as a benefit to Idaho customers in the form of a future rate reduction, and an additional $5.8 million of pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will be collected from customers in the future. As discussed below, Idaho Power recorded $18.1 million for the impact of a similar sharing mechanism in the third quarter of 2011.
Economic Conditions and Customer/Load Growth: When seeking to predict utility load changes for both short-term load forecasts and long-term infrastructure planning purposes, Idaho Power monitors a number of economic indicators, including employment rates, growth in customer numbers, and foreclosure rates and other housing-related data on both a national scale and within and around Idaho Power's service territory. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and Idaho Power's need for purchased power to meet demand.
Since 2008, economic conditions in Idaho Power's service territory have been relatively weak. However, a number of improvements in economic conditions have occurred over the last year and a half. After peaking at 10.0 percent in early 2011, the service area unemployment rate fell to 8.4 percent by the end of 2011 and reached 6.9 percent by the end of September 2012, according to Idaho Department of Labor data. The housing market in Idaho Power's service territory has improved when measured by foreclosure rates and the available supply and pricing of housing. Idaho Power also continues to experience customer growth.
During the 12 months ended September 30, 2012, the customer growth rate in Idaho Power's service territory was approximately 1.1 percent-roughly twice the growth rate of the prior two years. By comparison, for the 20-year period ending in 2011 the average annual customer growth rate in Idaho Power's service territory was 2.6 percent. Based on this data, Idaho Power predicts positive customer growth within its service territory in the next few years, though likely at a rate below the 20-year historical annual average. The foregoing general economic data and outlook is based, in part, on independent government and industry publications, reports by market research firms, or other independent sources.
While IDACORP and Idaho Power believe that these publications and other sources are reliable, the companies have not independently verified such data and can make no representation as to its accuracy.
Idaho Power cannot predict the timing of, and pace at which, economic recovery may occur in Idaho Power's service territory. As a result, Idaho Power continues to manage costs while executing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use.
Weather Conditions and Associated Impacts: Weather and agricultural growing conditions have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively. During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps. A four-percent increase in energy use by customers during the first nine months of 2012 compared to the first nine months of 2011 was largely attributable to agricultural growing conditions from April through September that required above average use of irrigation equipment and electric power to operate that equipment. Increased loads from irrigation equipment were particularly pronounced during the second quarter of 2012. As noted above, Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably the third quarter of each year when customer demand is typically at its peak. On July 12, 2012, Idaho Power achieved a record load demand of 3,245 MW.
The previous record load demand was 3,214 MW, set on June 30, 2008. At the time of the record load demand, Idaho Power had deployed 61 MW of demand response programs.
Idaho Power's hydroelectric facilities comprise approximately one-half of Idaho Power's nameplate generation capacity. The availability and volume of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power's hydroelectric facilities, reservoir storage, springtime snow pack run-off, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations. Idaho Power expects hydroelectric generation during 2012 to be in the range of 7.8 to 8.2 million megawatt-hours (MWh), based on reservoir storage levels and forecasted weather conditions as of the date of this report, compared to actual generation of 10.9 million MWh in 2011 and 7.3 million MWh in 2010. Median annual hydroelectric generation is 8.6 million MWh. For the nine months ended September 30, 2012, hydroelectric generation comprised 62 percent of Idaho Power's total system generation. Hydroelectric generation decreased 24 percent in the first nine months of 2012 compared to the first nine months of 2011 as a result of slightly below normal hydroelectric conditions in the current year. When hydroelectric generation is reduced Idaho 41-------------------------------------------------------------------------------- Table of Contents Power must rely on more expensive generation sources and purchased power; however, most of the increase in power supply costs is deferred as a regulatory asset and collected from customers through the PCA mechanisms. Conversely, in periods of greater hydroelectric generation most of the resulting decrease in power supply costs that typically occurs is returned to customers through the PCA mechanisms.
Where favorable hydroelectric generating conditions exist for Idaho Power, they also may be abundant for other Pacific Northwest hydroelectric facility operators, thus increasing the available supply of lower-cost power and depressing regional wholesale market prices, which impacts the revenue Idaho Power receives from off-system sales of its excess power. Conversely, when hydroelectric generating conditions are poor, wholesale market prices may be higher due to lower supply, but Idaho Power would have less surplus energy available for sale into the wholesale markets.
Fuel and Purchased Power Expense: In addition to hydroelectric generation and power it purchases in the wholesale markets, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities. Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's power generation capacity, the rate of expansion of alternative energy generation sources such as wind energy, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Operation of Idaho Power's newly constructed Langley Gulch power plant increases Idaho Power's use of natural gas as a generation source, and thus its exposure to volatility in natural gas prices.
Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is generally obligated to purchase power from PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices.
This increases the likelihood that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources (such as wind energy) into Idaho Power's portfolio also creates a number of complex operational risks and challenges, which Idaho Power is working to address, including through evaluation of the results of a recent comprehensive wind integration study. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,245 MW on July 12, 2012, wind resources on Idaho Power's system, representing roughly 500 MW of capacity, were contributing only 14 MW of power due to lack of wind.
The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in Idaho Power's power supply costs. Idaho Power also uses physical and financial forward contracts for both electricity and fuel in order to manage the risks relating to fuel and power price exposures.
Regulatory and Environmental Compliance Costs and Expenditures: Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits. Compliance with these requirements directly influences Idaho Power's operating environment and may significantly increase Idaho Power's operating costs. Further, potential monetary and non-monetary penalties for a violation of applicable laws or regulations may be substantial.
Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements those policies and initiatives. In particular, environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power shut down certain power generation plants. For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations in 2020. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power assesses, when and to the extent determinable, the potential impact on the costs to operate its power generation facilities, as well as the willingness or ability of joint owners of power plants to fund any required pollution control equipment upgrades in lieu of early plant retirements.
Other Notable Matters and Areas of Focus Pension Plans: Idaho Power contributed $44.3 million to its defined benefit pension plan in the first nine months of 2012, $18.5 million in 2011, and $60.0 million in 2010, and expects to make additional significant cash contributions in the coming years. The primary impact of pension plan contributions is on cash flows. Idaho Power defers pension costs related to its Idaho jurisdiction until those costs are recovered through rates. In May 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. In addition, the revenue sharing mechanism in Idaho Power's December 2011 settlement stipulation resulted in the recording of additional Idaho pension expense of $5.8 million during the three months ended September 30, 2012.
42-------------------------------------------------------------------------------- Table of Contents Water Management and Relicensing of Hydroelectric Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, Idaho Power is involved in renewing federal licenses for the Hells Canyon Complex (HCC), its largest hydroelectric generation source, and recently received a 30-year license renewal from the FERC for its Swan Falls hydroelectric project. Relicensing involves numerous environmental issues and substantial costs. Idaho Power is working with the states of Idaho and Oregon, regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of Idaho Power's hydroelectric projects. Given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial.
Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to improve system reliability and resource adequacy. Its most notable projects in progress include the proposed Boardman-to-Hemingway and Gateway West transmission projects. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. To further mitigate the risks associated with these projects, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC for the projects prior to construction. Based on Idaho Power's assessment of the status and future milestones for the Boardman-to-Hemingway project, Idaho Power has determined that an in-service date prior to 2018 is unlikely.
Environmental Sustainability Initiatives: As of the date of this report, Idaho Power is on-track to exceed the CO2 emission intensity reduction goal it established in 2009. Reflecting its further commitment to that goal, Idaho Power management plans to recommend to its board of directors that the board extend for an additional two-year period the CO2 emission intensity reduction goal, through 2015. At the same time, Idaho Power has been conducting a thorough analysis of the costs and methods for the integration of intermittent wind power into its energy portfolio, and expects to publicly release the results of that study during the fourth quarter of 2012. Further, in connection with its IRP process, Idaho Power has been conducting cost studies related to its jointly-owned coal-fired power plants, to determine whether plant upgrades that may be necessary to comply with environmental regulations are prudently incurred investments, or whether it is economically preferable to replace that generation with combined-cycle combustion turbine or other resources.
Summary of Third Quarter and Year-to-Date 2012 Financial Results The following is a summary of Idaho Power's net income, net income attributable to IDACORP, Inc., and IDACORP's earnings per diluted share for the three- and nine-month periods ended September 30, 2012 and 2011: Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Idaho Power net income $ 89,596 $ 104,872 $ 150,125 $ 155,420 Net income attributable to IDACORP, Inc. $ 92,069 $ 107,067 $ 152,299 $ 157,708 Average outstanding shares - diluted (000's) 50,080 49,622 49,990 49,499 IDACORP, Inc. earnings per diluted share $ 1.84 $ 2.16 $ 3.05 $ 3.19 43 -------------------------------------------------------------------------------- Table of Contents The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three- and nine-month periods ended September 30, 2012 to the same periods in 2011 (items are in millions and are before tax unless otherwise noted): Three months ended Nine months ended Net income attributable to IDACORP, Inc. - September 30, 2011 $ 107.1 $ 157.7 Change in Idaho Power net income: Rate and other regulatory changes, including pension expense recovery, power cost and fixed cost adjustment mechanisms $ 32.1 $ 43.5 Increase in sales volumes 3.0 19.3 Change in payroll-related expenses 2.3 (4.7 ) Additional pension expense funded through sharing and rate increases (5.8 ) (11.0 ) Increased depreciation expense, property tax, and other (2.7 ) (1.8 ) Greater revenue sharing in 2011 than in 2012 11.8 11.8 Increase in Idaho Power operating income 40.7 57.1 Change in allowance for funds used during construction (AFUDC) (4.2 ) 1.2 Other net changes (2.2 ) 4.2 Change from removal of additional amortization of ADITC in 2011 6.8 - Change in income tax expense (56.4 ) (67.8 ) Total decrease in Idaho Power net income (15.3 ) (5.3 ) Other net changes (net of tax) 0.3 (0.1 ) Net income attributable to IDACORP, Inc. - September 30, 2012 $ 92.1 $ 152.3 Third Quarter 2012 Net Income IDACORP net income decreased $15.0 million for the third quarter of 2012 when compared with the same period in the prior year, largely a result of the effect of an IRS examination settlement recorded during the third quarter in the prior year, when Idaho Power recognized approximately $56.9 million of previously unrecognized tax benefits related to the uniform capitalization method agreement with the IRS for tax years 2009 and prior. Largely offsetting the decrease in income related to the prior year examination settlement were several rate changes that combined to increase operating income by $32.1 million. These rate increases were the result of increased rates from a general rate case that took effect on January 1, 2012, increased rates related to the Langley Gulch power plant that took effect on July 1, 2012, and the impact of other rate changes and regulatory mechanisms that were effective concurrent with the summer rate season. Higher sales volumes also increased operating income by $3.0 million, driven by customer growth and warmer temperatures, which increased energy demand to operate air conditioning systems.
Effect of Sharing on Operating Income Three and nine months ended September 30, 2012 2011 Change Additional pension expense funded through sharing $ (5.8 ) $ - $ (5.8 ) Provision against current revenue as a result of sharing (6.3 ) (18.1 ) 11.8 Total $ (12.1 ) $ (18.1 ) $ 6.0 As a result of the rate and sales volume increases described above and their anticipated impact on annual net income, Idaho Power recorded a total of $12.1 million related to the settlement agreement approved by the IPUC in December 2011, which required sharing with customers a portion of 2012 Idaho-jurisdiction earnings exceeding a specified return on year-end equity. Of the total, $5.8 million was recorded as additional pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will need to be collected from customers in the future, and $6.3 million was a provision against current revenues to be refunded to customers through a future rate reduction. In the third quarter of 2011 Idaho Power recorded an $18.1 million provision against revenues to be refunded to customers.
44-------------------------------------------------------------------------------- Table of Contents Year-to-Date Net Income IDACORP's year-to-date net income was also impacted by the IRS examination settlements and sharing mechanisms discussed above, but only decreased $5.4 million compared to the same period in 2011. The impacts of changes in rates and other regulatory mechanisms and increased sales volumes offset most of the 2011 IRS examination settlements and sharing reserves. A warmer, drier spring in 2012 caused significant increases in irrigation usage when compared with the prior year. Warmer summer temperatures, which drove slight increases in residential usage in the third quarter, were offset by relatively mild winter temperatures experienced earlier in the year, which reduced sales to residential customers for heating purposes. In total, sales volume changes increased operating income by $19.3 million. A rate increase resulting from a general rate case in the Idaho jurisdiction that took effect on January 1, 2012, combined with increased rates related to the Langley Gulch power plant that took effect on July 1, 2012, and the impacts of other rate changes and regulatory mechanisms, increased operating income by $43.5 million.
Key Operating and Financial Metric Estimates for Full-Year 2012 IDACORP's and Idaho Power's estimates, as of the date of this report, for 2012 full year metrics are as follows: 2012 Estimates Current Previous (4) (5)Idaho Power Operating & Maintenance Expense (millions)(1) $335-$345 $325-$335 Idaho Power Additional Amortization of ADITC (millions) No Change None Idaho Power Capital Expenditures (millions)(2) No Change $230-$235 Idaho Power Hydroelectric Generation (million MWh)(3) 7.8-8.2 7.5-8.5 Non-regulated subsidiary earnings and holding company No Change $0.0-$3.0 expenses (millions) (1) Increase in the range reflects the estimated amount of additional pension expense to be recognized related to the Idaho sharing arrangement. No expected impact to net income as a result of the increase.
(2) The range for capital expenditures includes (among other items) the completion of the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman-to-Hemingway and Gateway West transmission projects (net of ongoing payments from third parties participating as joint funders in the permitting projects), excluding AFUDC.
(3) Based on reservoir storage levels and forecasted weather conditions as of the date of this report.
(4) As of November 1, 2012.
(5) As of August 2, 2012, the date of filing of IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.
RESULTS OF OPERATIONS This section of MD&A takes a closer look at the significant factors that affected IDACORP's and Idaho Power's earnings during the three and nine months ended September 30, 2012. In this analysis, the results for the three and nine months ended September 30, 2012 are compared to the same periods in 2011. In MD&A, MWh and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.
45-------------------------------------------------------------------------------- Table of Contents Utility Operations The table below presents Idaho Power's energy sales and supply (in thousands of MWh) for the three and nine months ended September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 General business sales 4,304 4,239 10,941 10,524 Off-system sales 109 747 1,656 2,794 Total energy sales 4,413 4,986 12,597 13,318 Hydroelectric generation 1,649 2,790 6,630 8,683 Coal generation 1,653 1,482 3,505 3,370 Natural gas and other generation 410 83 610 124 Total system generation 3,712 4,355 10,745 12,177 Purchased power 1,026 974 2,871 2,157 Line losses (325 ) (343 ) (1,019 ) (1,016 ) Total energy supply 4,413 4,986 12,597 13,318 General Business Revenues: The table below presents Idaho Power's general business revenues and MWh sales for the three and nine months ended September 30, 2012 and 2011 and the number of customers as of September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Revenue Residential $ 120,786 $ 103,035 $ 316,964 $ 302,464 Commercial 72,519 61,630 181,810 169,229 Industrial 41,690 38,496 108,804 105,098 Irrigation 80,780 70,596 131,057 99,467 Total 315,775 273,757 738,635 676,258 Provision for sharing (6,300 ) (18,100 ) (6,300 ) (18,100 ) Deferred revenue related to HCC (3,409 ) (3,344 ) (8,310 ) (8,277 ) relicensing AFUDC(1) Total general business revenues $ 306,066 $ 252,313 $ 724,025 $ 649,881 Volume of Sales (MWh) Residential 1,285 1,246 3,757 3,786 Commercial 1,044 1,035 2,911 2,867 Industrial 793 783 2,333 2,294 Irrigation 1,182 1,175 1,940 1,577 Total MWh sales 4,304 4,239 10,941 10,524 Customer Count (period end) Residential 414,640 410,079 Commercial 65,782 65,061 Industrial 119 124 Irrigation 19,071 18,807 Total customers 499,612 494,071 (1) As part of its January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.7 million annually in the Idaho jurisdiction, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.
46-------------------------------------------------------------------------------- Table of Contents Changes in rates and changes in customer demand are the primary reasons for fluctuations in general business revenue from period to period. The table below presents the rate changes that significantly impacted revenue levels for the third quarter and the first nine months of 2012 compared to the same periods in 2011.
Percentage Rate Increase Annualized $ Impact Description Effective Date (Decrease) (millions) 2011 Idaho PCA 6/1/2011 (4.8 )% $ (40 ) 2011 Idaho pension expense recovery 6/1/2011 1.4 % 12 2011 Idaho general rate case settlement agreement 1/1/2012 4.1 % 34 2012 Idaho PCA 6/1/2012 5.1 % 43 2012 Idaho non-AMI meter depreciation 6/1/2012 (1.3 )% (11 ) 2012 Idaho Langley Gulch 7/1/2012 6.8 % 58 The primary factors influencing customer demand are weather and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps, with increased precipitation reducing electricity sales. Boise, Idaho weather conditions for the three and nine months ended September 30, 2012 and 2011 are included in the table below.
Three months ended Nine months ended September 30, September 30, 2012 2011 Normal 2012 2011 Normal Heating degree-days (1) 17 10 121 2,865 3,438 3,319 Cooling degree-days (1) 1,074 969 751 1,273 1,054 934 (1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.
General business revenue increased $53.8 million for the quarter and $74.1 million for the year-to-date compared to the same periods in 2011. The factors affecting general business revenues are discussed in more detail below.
• Rates. The rate changes listed above combined to increase general business revenue by $43.9 million for the quarter and $48.8 million year-to-date compared to the same periods in 2011. Rates are seasonally adjusted and based on a tiered rate structure that provides for higher rates during higher-usage periods. These seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings.
The revenue impact of several of the rate changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense was reduced $6.4 million for the quarter and $19.5 million year-to-date compared to the same periods in 2011 due to the change in the corresponding Idaho PCA rate in the prior year.
Idaho-jurisdiction pension expense recovery and FCA rate changes were fully offset by related amortizations.
• Sharing. A part of the increase in revenue resulted from revenue sharing mechanisms in place in both years. The impact of these mechanisms is recorded as a reduction to general business revenue. For both the quarter and year-to-date, $6.3 million was recorded in the current year and $18.1 million was recorded in the prior year, for a net increase to general business revenue of $11.8 million in the current year. The revenue sharing mechanisms are associated with two Idaho regulatory agreements that provide for the sharing of Idaho-jurisdiction earnings exceeding a specified Idaho ROE. The amounts recorded reflect amounts to be refunded to customers. The smaller amount recorded in the current year when compared with the same period in the prior year is partially due to changes in the terms of the mechanism in place in each year.
• Customers. Moderate customer growth drove an increase in overall MWh sales for the quarter and year-to-date. Total customers increased 1.0 percent for the quarter and 0.9 percent year-to-date compared to the same periods in 2011. Customer growth was offset by changes in revenue related to a large industrial customer. These changes combined caused a $1.2 million decrease in general business revenues for the quarter and increased general business revenues by $3.3 million year-to-date when compared to the same periods in 2011.
47-------------------------------------------------------------------------------- Table of Contents • Usage. The revenue impact of customer growth was also offset for the third quarter of 2012 by lower usage per customer, which decreased general business revenue by $0.7 million compared to the third quarter of 2011.
Higher residential usage per customer, which increased 2.1 percent for the quarter due to a 10.8 percent increase in cooling degree days, drove demand for electricity to operate air conditioning units. Commercial usage per customer also increased by 0.7 percent for the quarter when compared with the same period in 2011. Offsetting these increases was decreased irrigation usage per customer, which declined 4.1 percent when compared to the same period in 2011.
For the nine months ended September 30, 2012, higher usage per customer increased revenues by $10.2 million. Irrigation usage per customer was 13.8 percent higher for the period due to agricultural growing conditions in the second quarter, including warmer temperatures that allowed for earlier planting of crops, and due to lower relative springtime precipitation, which resulted in greater use of irrigation pumps compared to the same growing season in the prior year. For the year-to-date, commercial usage per customer increased 1.2 percent, while residential per customer usage decreased by 1.6 percent. The modest decrease in year-to-date residential usage per customer is due primarily to relatively mild winter and spring temperatures, which decreased demand for heating purposes.
Off-System Sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The table below presents Idaho Power's off-system sales for the three and nine months ended September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Revenue $ 4,826 $ 24,083 $ 43,953 $ 74,648 MWh sold 109 747 1,656 2,794 Revenue per MWh $ 44.28 $ 32.24 $ 26.54 $ 26.72 For the quarter and the year-to-date, off-system sales revenue decreased by $19.3 million, or 80 percent, and $30.7 million, or 41 percent, respectively, as compared to the same periods in 2011. Off-system sales volumes decreased 85 percent for the quarter and 41 percent for the first nine months of 2012, as a result of decreased hydroelectric generation and increased system load when compared to the same periods in 2011. The decreases in volume were partially offset by a 37 percent increase in average prices for the quarter and modestly impacted by a 1 percent decrease in average prices for the first nine months of 2012.
Other Revenues: The table below presents the components of other revenues for the three and nine months ended September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Transmission services and other $ 13,455 $ 13,145 $ 37,839 $ 37,491 Energy efficiency 8,410 18,504 20,971 31,011 Total other revenues $ 21,865 $ 31,649 $ 58,810 $ 68,502 Other revenue decreased $9.8 million and $9.7 million for the third quarter and first nine months of 2012, respectively, compared to the same periods in 2011.
Demand response incentive payments to customers, which had been treated as an energy efficiency expense and recovered through the energy efficiency rider in 2011 and prior, are being recorded as purchased power expense (discussed below) and recovered through the PCA mechanism during 2012, as discussed in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.
Most energy efficiency activities are funded through a rider mechanism on customer bills. Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected. As of September 30, 2012, Idaho Power's total Idaho and Oregon jurisdictional energy efficiency rider balance was a net regulatory asset of $1.5 million.
48-------------------------------------------------------------------------------- Table of Contents Purchased Power: The table below presents Idaho Power's purchased power expenses and volumes for the three and nine months ended September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Expense PURPA contracts $ 35,483 $ 28,095 $ 88,842 $ 66,929 Other purchased power (including wheeling) 22,862 38,046 47,837 60,729 Demand response incentive payments 13,225 - 14,347 - Total purchased power expense $ 71,570 $ 66,141 $ 151,026 $ 127,658 MWh purchased PURPA contracts 497 415 1,489 1,123 Other purchased power 529 559 1,382 1,034 Total MWh purchased 1,026 974 2,871 2,157 Cost per MWh from PURPA contracts $ 71.39 $ 67.70 $ 59.67 $ 59.60 Cost per MWh from other sources $ 43.22 $ 68.06 $ 34.61 $ 58.73 Weighted average - all sources $ 56.87 $ 67.91 $ 47.61 $ 59.18 Purchased power expense increased $5.4 million, or 8 percent, in the third quarter of 2012 and $23.4 million, or 18 percent, in the first nine months of 2012, compared to the same periods in 2011. This increase was driven by the volume of mandated power purchases from cogeneration and small power production (CSPP) facilities pursuant to PURPA, which increased 20 percent for the quarter and 33 percent in the first nine months of 2012 due to new PURPA wind generation facilities coming on-line. In addition, for the year-to-date, there was less hydroelectric generation available than in the prior year, at the same time that loads increased.
The increases in contract purchases were partially offset by a 40 percent and 43 percent decrease in the average price of wholesale purchased power, excluding wheeling costs, for the quarter and the year-to-date, respectively. Further, beginning in June 2012, demand response program incentive payments were included in purchased power expenses, for recovery through base rates and the PCA mechanism, whereas in 2011 the incentives were recovered through the energy efficiency rider mechanism.
Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the increased expense associated with PURPA power purchases is a corresponding increase in customer rates.
49-------------------------------------------------------------------------------- Table of Contents Fuel Expense: The table below presents Idaho Power's fuel expenses and generation at its thermal generating plants for the three and nine months ended September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Expense Coal $ 41,905 $ 35,805 $ 90,041 $ 81,050 Natural gas and other(1) 14,073 5,390 19,973 9,751 Total fuel expense $ 55,978 $ 41,195 $ 110,014 $ 90,801 MWh generated Coal 1,653 1,482 3,505 3,370 Natural gas and other(1) 410 83 610 124 Total MWh generated 2,063 1,565 4,115 3,494 Cost per MWh Coal $ 25.35 $ 24.16 $ 25.69 $ 24.05 Natural gas and other $ 34.32 $ 64.94 $ 32.74 $ 78.64 Weighted average, all sources $ 27.13 $ 26.32 $ 26.73 $ 25.99 (1) Excludes 129 MWh of generation from the Langley Gulch power plant in the second quarter of 2011 for which costs were capitalized during the construction and testing phase of the plant. The Langley Gulch power plant became commercially available on June 29, 2012.
Fuel expense increased $14.8 million, or 36 percent, in the third quarter of 2012 and $19.2 million, or 21 percent, in the first nine months of 2012 compared to the same periods in 2011, due principally to the following factors: • Idaho Power's Langley Gulch plant came on line at the end of the second quarter of 2012. Operation of the plant accounted for $8.3 million of the increase in fuel expense for the quarter and the year-to-date. Idaho Power operated the plant to serve peak load. In addition, Idaho Power operated the plant to integrate intermittent resources and for economic dispatch opportunities.
• Generation from coal-fired facilities increased 12 percent for the quarter and 4 percent for the first nine months compared to the same periods in 2011. During the quarter, higher wholesale power prices and lower hydroelectric generation when compared with the same period in the prior year increased Idaho Power's reliance on its coal-fired plants to meet customer loads.
• Along with the increases in coal- and natural gas-fired electric generation, commodity prices were higher at the coal plants for the quarter and year-to-date when compared with the same periods in the prior year. Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the two periods. The relatively large cost per MWh for natural gas facilities during the three- and nine-month periods of 2011, as shown in the table above, was the result of the allocation of fixed costs over a low volume of output.
PCA Mechanisms: Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets. To address the volatility of power supply costs, Idaho Power has PCA mechanisms in both the Idaho and Oregon jurisdictions. These mechanisms allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs. Because of these mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.
50-------------------------------------------------------------------------------- Table of Contents PCA expense represents the effects of the Idaho and Oregon PCA mechanisms. The table below presents the components of the Idaho and Oregon PCA mechanisms for the three and nine months ended September 30, 2012 and 2011.
Three months ended Nine months ended September 30, September 30, 2012 2011 2012 2011 Idaho power supply cost (deferral) $ (36,320 ) $ (9,845 ) $ (25,709 ) $ 25,756 accrual Oregon power supply cost (deferral) - (159 ) (1,523 ) 1,159 accrual Amortization of prior year authorized (6,551 ) (185 ) (9,842 ) 9,703 balances Total power cost adjustment expense $ (42,871 ) $ (10,189 ) $ (37,074 ) $ 36,618 The power supply accruals or deferrals represent the portion of that periods' power supply cost fluctuations accrued or deferred under the PCA mechanisms.
Accruals represent additional costs recorded because actual power supply costs were less than the amount forecasted in PCA rates. The power supply cost deferral in the third quarter of 2012 is greater than in 2011 because actual power supply costs in 2012 were higher than the amounts forecasted in PCA rates.
If actual power supply costs are greater than the amount forecasted in PCA rates, most of the excess is deferred. The amortization of the prior year's balances represents the amounts being collected or refunded in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).
Other Operations and Maintenance (O&M) Expenses: Other O&M expense increased $5.4 million for the quarter and $13.8 million for the year-to-date as compared to the same periods in 2011. The changes in other O&M expense were due to the following: • an increase in pension expense of $5.8 million and $11.0 million for the quarter and first nine months, respectively. This increase resulted from a $5.8 million third quarter sharing accrual under Idaho Power's December 2011 settlement agreement, which benefits Idaho customers through an offset to the deferred pension regulatory asset. The remainder of the year-to-date increase represents pension expenses that increased in June 2011 concurrent with increased recovery of deferred pension costs in rates; • changes in labor and benefits costs, which declined $2.3 million for the quarter and increased $4.7 million year-to-date. These changes resulted from normal increases in employee wages and costs of providing employee benefits. The change for the quarter was also affected by variations in timing of labor expenses recorded in the current year compared to the prior year; • increases in administrative and other costs of $3.2 million for the quarter and $7.4 million for the comparative year-to-date, primarily related to increases in consultant costs, software licenses and maintenance, and other purchased services. A significant portion of the increase related to a lower reimbursement from the U.S. Department of Energy for Smart Grid-related items in 2012 compared to 2011; and • decreased thermal plant O&M costs of $0.7 million for the quarter and $9.0 million for the year-to-date related to costs for maintenance outages that occurred in 2011 that did not recur in 2012, as well as lower overall maintenance costs as the plants experienced less wear and tear due to lower utilization during the first half of 2012. The lower utilization was predominately driven by low wholesale energy prices in the region during that period.
Income Taxes Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the nine months ended September 30, 2012, compared to the same period in 2011, increased $66.9 million and $67.8 million, respectively, primarily as a result of greater Idaho Power pre-tax earnings and IRS examination settlements in 2011, partially offset by a tax accounting method change at Idaho Power. For information relating to IDACORP's and Idaho Power's computation of income tax expense and estimated annual effective tax rate, see Note 2 - "Income Taxes" to the condensed consolidated financial statements included in this report.
Accelerated Amortization of ADITC: Idaho Power's December 2011 settlement stipulation with the IPUC and other parties provided for the availability of additional amortization of ADITC if Idaho Power's actual Idaho ROE is below 9.5 percent in any calendar year from 2012 to 2014. For information relating to Idaho Power's 2011 settlement stipulation, see Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. In accordance with the settlement stipulation, Idaho Power has $25 million of additional ADITC amortization available for use in 2012. Based on its estimate of full year Idaho ROE, Idaho Power has no additional ADITC amortization recorded for the nine months ended 51-------------------------------------------------------------------------------- Table of Contents September 30, 2012. As of the date of this report, Idaho Power does not expect to record additional ADITC amortization for full year 2012.
Bonus Depreciation: Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes. For 2012, the deduction is equal to 50 percent of a qualifying asset's cost. Idaho Power has included an estimated bonus depreciation deduction in its current federal income tax provision.
LIQUIDITY AND CAPITAL RESOURCES Overview IDACORP's and Idaho Power's operating cash flows are driven principally by Idaho Power's sales of electricity and transmission capacity. Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, capital expenditures, pension plan contributions, and interest. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, and at the same time the prices can be volatile and difficult to predict, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as these costs, with interest, are recovered from customers.
Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP. Idaho Power periodically files for rate adjustments to recover increased operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators. Idaho Power is in a period of significant infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability. Idaho Power's hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial. As a result of these and other projects, Idaho Power estimates that total capital expenditures will be between $720 million and $735 million over the period from 2012 (inclusive of amounts incurred year-to-date in 2012) through 2014.
As of October 26, 2012, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included: • their respective $125 million and $300 million revolving credit facilities; • IDACORP's shelf registration statement, which it may use for the issuance of debt securities and common stock, including up to 3.0 million shares of IDACORP common stock available for issuance under its continuous equity program. Approximately $539 million of debt and equity securities issuances remained available under the shelf registration statement; • Idaho Power's shelf registration statement, which it may use for the issuance of first mortgage bonds and debt securities; $150 million remained available under the shelf registration statement, which expires in May 2013; and • IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available capacity under their respective credit facilities, and is used to meet short-term liquidity requirements.
IDACORP and Idaho Power expect to continue financing capital requirements during 2012 and into 2013 with a combination of internally generated funds and externally financed capital, and believe that access to their credit facilities and operating cash flows generated by Idaho Power's utility business are sufficient to meet short-term obligations. To meet long-term maturing debt obligations and costs of infrastructure development, such as Idaho Power's 500-kV transmission projects, the companies may use a combination of internally generated funds, credit facilities, the issuance of long-term debt or equity and, in the case of Idaho Power, capital contributions from IDACORP. Should economic or financing conditions deteriorate, the companies may be required to defer or eliminate certain capital expenditures, to the extent it can do so while maintaining the reliability of its system and service and timely complying with environmental and regulatory obligations. The conditions of the capital markets and the weak economy have in recent years caused a general concern regarding access to sufficient capital at a reasonable cost. Notwithstanding this concern, IDACORP and Idaho Power have not been significantly affected by this disruption in the credit environment, including in the commercial paper markets, and currently expect to continue to be able to access the capital markets to meet anticipated short- and long-term borrowing needs.
52-------------------------------------------------------------------------------- Table of Contents Idaho Power issued $150 million of first mortgage bonds, medium-term notes in April 2012, using a portion of the net proceeds to redeem prior to maturity $100 million of first mortgage bonds, medium-term notes due November 2012. IDACORP and Idaho Power have no other debt maturities in 2012 and expect a minimal need for any additional external financing in 2012, other than issuances of commercial paper to meet cash balancing needs from time-to-time. Idaho Power has $70 million of first mortgage bonds, medium-term notes, due in October 2013, with no first mortgage bonds due thereafter until 2018.
During the first half of 2012, IDACORP continued to issue common stock under the pre-existing dividend reinvestment and employee-related stock purchase plans.
Effective July 1, 2012, IDACORP discontinued original issuances of common stock and instructed the plan administrators to use market purchases of IDACORP common stock for purposes of acquiring IDACORP common stock for the IDACORP, Inc.
Dividend Reinvestment and Stock Purchase Plan and the Idaho Power Company Employee Savings Plan. However, IDACORP may determine at any time to resume original issuances of common stock under those plans. IDACORP may also determine to issue common stock from time-to-time under its continuous equity program, depending on market conditions and capital needs. IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of September 30, 2012, IDACORP's and Idaho Power's capital structures were as follows: IDACORP Idaho Power Debt 47% 49% Equity 53% 51% Operating Cash Flows IDACORP's and Idaho Power's operating cash inflows for the nine months ended September 30, 2012 were $181 million and $176 million, respectively. IDACORP's and Idaho Power's operating cash flows decreased by $53 million and $50 million, respectively, compared to the nine months ended September 30, 2011. With the exception of cash flows related to income taxes, IDACORP's operating cash flows are principally derived from the operating cash flows of Idaho Power.
Significant items that affected the companies' operating cash flows in the first nine months of 2012 relative to the same period in 2011 were as follows: • Idaho Power made contributions of $44.3 million to its defined benefit pension plan during the first nine months of 2012, while it made $18.5 million of cash contributions during the first nine months of 2011; • cash outflows related to income taxes increased by $13 million and $8 million for IDACORP and Idaho Power, respectively. IDACORP had net income tax payments of $1 million in 2012 compared with net refunds of nearly $12 million in 2011. Idaho Power's net payments to IDACORP for income tax were $1 million for the nine months ended September 30, 2012, compared with net refunds of $7 million for the same period in 2011; • changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $74 million, as Idaho Power collected $20 million less of previously deferred costs and incurred $54 million less in the current year accrual, as compared with the first nine months of 2011; and • the company's investment in BCC resulted in a net distribution to Idaho Power of $12 million for the first nine months of 2012, as compared to a net distribution of $1 million for the first nine months of 2011. The change in net distribution from year to year is the result of increased net income at BCC and the impact of timing differences associated with BCC incurring costs for reclamation activities and the reimbursement of those costs from the established reclamation trust fund.
Investing Cash Flows Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power's generation, transmission, and distribution facilities. IDACORP's and Idaho Power's investing cash outflows for the nine months ended September 30, 2012 were $185 million, a decrease of $75 million compared to the nine months ended September 30, 2011. Investing cash outflows for 2012 and 2011 were primarily for construction of utility infrastructure needed to address Idaho Power's peak demand growth, aging plant and equipment, and forecasted customer growth. The expenditures during the first nine months of 2012 for additions to property, plant, and equipment were less than the same period in 2011, largely as a result of reduced activity related to the Langley Gulch power plant, as the plant became commercially available on June 29, 2012.
53-------------------------------------------------------------------------------- Table of Contents Financing Cash Flows Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets, and credit facilities. IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.
IDACORP's financing cash outflows for the nine months ended September 30, 2012 were $4 million and Idaho Power's financing cash inflows were $3 million for the same period. The following are significant items that affected financing cash flows in the first nine months of 2012: • in May 2012, Idaho Power redeemed prior to maturity $100 million of outstanding first mortgage bonds due November 2012 using a portion of the proceeds from the $150 million of first mortgage bonds issued in April 2012; • IDACORP and Idaho Power paid cash dividends of approximately $50 million; and • IDACORP made a capital contribution of $7.5 million to Idaho Power.
On June 17, 2010, Idaho Power entered into a Selling Agency Agreement with Banc of America Securities LLC; BNY Mellon Capital Markets, LLC; J.P. Morgan Securities Inc.; KeyBanc Capital Markets Inc.; Merrill Lynch, Pierce, Fenner & Smith Incorporated; Mitsubishi UFJ Securities (USA), Inc.; RBC Capital Markets Corporation; SunTrust Robinson Humphrey, Inc.; U.S. Bancorp Investments, Inc.; and Wells Fargo Securities, LLC in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds under a shelf registration statement. In August 2010, Idaho Power issued $200 million of first mortgage bonds, medium-term notes, Series I, under the shelf registration statement. On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022 and $75 million of 4.30% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042, under the Selling Agency Agreement and shelf registration statement. In April 2012, Idaho Power issued an irrevocable notice of redemption to redeem, prior to maturity, its $100 million in principal amount of 4.75% first mortgage bonds, medium-term notes due November 2012. In May 2012, Idaho Power used a portion of the net proceeds of the April 2012 issuance of first mortgage bonds, medium-term notes to effect the redemption.
Financing Programs Shelf Registrations: IDACORP has an effective registration statement that, as of the date of this report, can be used for the issuance of up to $539 million of debt securities and common stock. Idaho Power has an effective registration statement that, as of the date of this report, can be used for the issuance of up to $150 million of first mortgage bonds and unsecured debt. Refer to Note 4 - "Long-Term Debt" to the condensed consolidated financial statements included in this report for more information regarding long-term financing arrangements.
The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust, market conditions, regulatory authorizations, and covenants contained in other financing agreements. The Indenture of Mortgage and Deed of Trust limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of September 30, 2012, Idaho Power could issue approximately $1.3 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of September 30, 2012 was limited to approximately $489 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust.
Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million.
Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed 54-------------------------------------------------------------------------------- Table of Contents $30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.
Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, "consolidated indebtedness" broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). "Consolidated total capitalization" is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At September 30, 2012, the leverage ratios for IDACORP and Idaho Power were 47 percent and 49 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At September 30, 2012, IDACORP and Idaho Power were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not believe they will be in violation or breach of its significant debt covenants during the remainder of 2012, but were circumstances to arise that may alter that view management would take appropriate action to mitigate any such issue.
The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurrence of certain environmental liabilities, subject, in certain instances, to cure periods.
Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.
While the credit facilities provide for an original maturity date of October 26, 2016, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On October 12, 2012, IDACORP and Idaho Power executed First Extension Agreements with each of the lenders, extending the maturity date under both agreements to October 26, 2017. No other terms of the credit agreements, including the amount of permitted borrowings under the credit agreements, were affected by the extension.
Without additional approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.
Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they may issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.
55-------------------------------------------------------------------------------- Table of Contents Available Short-Term Liquidity: The table below outlines available short-term borrowing liquidity as of the dates specified.
September 30, 2012 December 31, 2011 IDACORP(2) Idaho Power IDACORP(2) Idaho Power Revolving credit facility $ 125,000 $ 300,000 $ 125,000 $ 300,000 Commercial paper outstanding (51,400 ) - (54,200 ) - Identified for other use (1) - (24,245 ) - (24,245 ) Net balance available $ 73,600 $ 275,755 $ 70,800 $ 275,755 (1) Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds is unable to sell the bonds to third parties.
(2) Holding company only.
At October 26, 2012, IDACORP had no loans outstanding under its credit facility and $70 million of commercial paper outstanding, and Idaho Power had no loans outstanding under its credit facility and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the three- and nine-month periods ended September 30, 2012.
Three months ended Nine months ended September 30, 2012 September 30, 2012 IDACORP (1) Idaho Power IDACORP (1) Idaho Power Commercial paper: Period end: Amount outstanding $ 51,400 $ - $ 51,400 $ - Weighted average interest rate 0.47 % - % 0.47 % - % Daily average amount outstanding during the period $ 52,543 $ 9,500 $ 54,342 $ 4,835 Weighted average interest rate during the period 0.48 % 0.48 % 0.47 % 0.47 % Maximum month-end balance $ 52,000 $ 12,000 $ 61,500 $ 12,000 (1) Holding company only Impact of Credit Ratings on Liquidity and Collateral Obligations IDACORP's and Idaho Power's access to capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on their respective credit ratings. The table below outlines the ratings of Idaho Power's and IDACORP's securities, and the ratings outlook, by Standard & Poor's Ratings Services and Moody's Investors Service as of the date of this report.
S&P Moody's Idaho Power IDACORP Idaho Power IDACORP Corporate Credit Rating/Long-Term Issuer Rating BBB BBB Baa 1 Baa 2 Senior Secured Debt A- None A2 None Senior Unsecured Debt BBB None Baa 1 None Short-Term Tax-Exempt Debt BBB/A-2 None Baa 1/ VMIG-2 None Commercial Paper A-2 A-2 P-2 P-2Senior Unsecured Credit Facility None None Baa 1 Baa 2 Rating Outlook Stable Stable Stable Stable These security ratings reflect the views of the ratings agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.
56-------------------------------------------------------------------------------- Table of Contents Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties. As of September 30, 2012, Idaho Power had posted $1 million of performance assurance collateral. Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions. Based upon Idaho Power's current energy and fuel portfolio and market conditions as of September 30, 2012, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $4.5 million. To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.
Capital Requirements Idaho Power's construction expenditures were $188 million and $267 million during the nine months ended September 30, 2012 and 2011, respectively. The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2012 (including amounts incurred to date during 2012) through 2014 (in millions of dollars).
2012 2013-2014 Ongoing capital expenditures $200-205 $490-500 Langley Gulch Power Plant (detailed below) 30 - Total $230-235 $490-500 Major Infrastructure Projects: Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of certain of these projects and notable developments since the discussion of these matters included in Part II, Item 7 - "MD&A - Capital Requirements" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.
The discussion below should be read in conjunction with that report.
Langley Gulch Power Plant: The Langley Gulch power plant is a natural gas-fired combined cycle combustion turbine generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW.
Idaho Power placed the plant in service on June 29, 2012. Idaho Power incurred $396 million, including AFUDC, of capital expenditures associated with the project from inception in 2009 through September 2012.
Boardman-to-Hemingway Line: The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, would provide transmission service to meet needs identified in the 2011 Integrated Resource Plan (IRP). In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to jointly pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Idaho Power's estimated share of the cost of the permitting phase of the project is $13 million, including AFUDC. Total cost estimates for the project are between approximately $890 million and $940 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate.
Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.
Federal and state permitting continues to move forward with a draft environmental impact statement (EIS) expected to be issued in the first half of 2013. The completion date of the project is subject to siting, permitting, regulatory approvals, in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other conditions. Based on Idaho Power's assessment of those and other factors, as of the date of this report Idaho Power estimates that a project in-service date prior to 2018 is unlikely. Idaho Power will evaluate the impact of the new in-service date estimate in its 2013 IRP and determine if Idaho Power needs to take additional actions to ensure that it reliably meets load service obligations.
On October 2, 2012, the BPA issued a statement that it had completed an initial prioritization of potential service arrangements for its customer load in southeastern Idaho and, while it had not made a final decision on options for this service, the BPA 57-------------------------------------------------------------------------------- Table of Contents identified the Boardman-to-Hemingway line with a transmission asset swap as a top priority for pursuit during 2013 and beyond. According to the BPA, of the options it evaluated, the Boardman-to-Hemingway line with a transmission asset swap has the potential to keep the BPA's costs low, relative to the other options considered.
Gateway West Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $24 million, including AFUDC. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $150 million and $300 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above.
Construction costs are not included in the table above. Timing of the construction of each segment of the project is subject to siting, permitting, regulatory approvals, in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other conditions. On October 4, 2012, the U.S. Bureau of Land Management (BLM) released its preferred route for the project, and Idaho Power is reviewing the implications of that route, including the potential impact on project costs.
Idaho Power anticipates continued engagement with stakeholders as the route is evaluated. The BLM's schedule provides for the issuance of a final EIS in the fourth quarter of 2012 and a record of decision in mid-2013.
Memorandum of Understanding, dated January 12, 2012, among Idaho Power, PacifiCorp, and BPA (2012 MOU): Executed in connection with the BPA's participation in the joint funding agreement for the Boardman-to-Hemingway line, the 2012 MOU provides that the parties will negotiate in good faith the terms of mutually satisfactory definitive agreements that would allow BPA to meet its load service obligations in southeast Idaho. It provides that the parties will explore opportunities to establish eastern Idaho load service from the Hemingway substation in exchange for similar service from the Federal Columbia River Transmission System. The 2012 MOU outlines at least two potential alternatives for further negotiation, including a network service option and an asset ownership rights option on the parties' transmission systems, both of which include BPA participation in the Boardman-to-Hemingway transmission line. Any party may terminate the 2012 MOU at any time, without penalty, and the 2012 MOU automatically expires on December 31, 2014.
AMI/Smart Grid and American Recovery and Reinvestment Act of 2009 (ARRA): The advanced metering infrastructure project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. In December 2011, Idaho Power completed the installation of its advanced metering technology at a cost of $71.8 million. Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. The grant was signed by the DOE in April 2010 and applies to project costs, including those associated with the AMI project, incurred beginning in August 2009 for a three-year term.
As of September 30, 2012, Idaho Power had invoiced approximately $39.1 million to the DOE, of which $37.5 million had been received. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.
Changes to Capital Project Mix: At times, Idaho Power may seek to accelerate, scale back, modify, or eliminate projects, or seek alternative projects, to accommodate anticipated resource needs and to help ensure its ability to provide reliable electric service and meet load and transmission capacity obligations.
Scaling back or eliminating a project due to regulatory challenges or other factors influencing the feasibility of a project may result in Idaho Power pursuing one or more separate, more costly projects. For instance, if Idaho Power were unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, it may terminate those projects and, as an alternative, develop additional generation facilities within areas where Idaho Power has available transmission capacity. Idaho Power's IRP seeks to address these potential alternatives and their associated risks and costs. Termination of a project carries with it the potential for a write-off of all or a significant portion of the costs associated with the project.
Defined Benefit Pension Plan Contribution: During the first nine months of 2012, Idaho Power contributed $44.3 million to its defined benefit pension plan. Idaho Power contributed $18.5 million to its defined benefit pension plan in 2011 and $60 million in 2010. As reported in more detail in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, Idaho Power expects to make additional significant cash contributions to its defined benefit pension plan in coming years. Idaho Power has evaluated the potential impact of recently approved federal legislation that will alter the timing and amount of future contributions to the defined benefit pension plan. The legislation, signed into law in July 2012, provides a smoothing mechanism applicable to the calculation of plan minimum contributions, and will reduce minimum amounts required to be contributed to the plan in at least the next few years. The legislation's partial funding relief is automatically effective for all contributions beginning in 2013, and Idaho Power chose to adopt the funding relief for its 2012 contributions. In May 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. The primary impact of pension contributions is on cash flows.
58-------------------------------------------------------------------------------- Table of Contents Contractual Obligations IDACORP's and Idaho Power's contractual obligations, outside of the ordinary course of business, have not changed materially from the amounts disclosed in their Annual Report on Form 10-K for the year ended December 31, 2011, except as follows: • nine power purchase agreements were terminated due to either an uncured breach by the respective counterparties or pursuant to IPUC-approved settlement arrangements between the parties, which reduced Idaho Power's contractual payment obligations by approximately $736 million over the 15-year to 25-year lives of the contracts; and • Idaho Power issued $150 million of first mortgage bonds, medium-term notes (long-term indebtedness), using a portion of the net proceeds from that issuance to redeem prior to maturity $100 million of outstanding first mortgage bonds, medium-term notes due November 2012.
Dividends The amount and timing of dividends paid on IDACORP's common stock are within the discretion of IDACORP's board of directors. IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP's current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant. The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the IDACORP board of directors' dividend decisions.
Notwithstanding the dividend policy adopted by the IDACORP board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the foregoing factors, among others.
On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend, commencing with the dividend paid on February 29, 2012, to $0.33 per share of IDACORP common stock, from the prior quarterly dividend amount of $0.30 per share of IDACORP common stock. On September 20, 2012, IDACORP's board of directors voted to increase the quarterly dividend again in 2012, commencing with the dividend payable on November 30, 2012, to $0.38 per share of IDACORP common stock. In its September 20 press release, IDACORP stated that based on IDACORP's then-current estimates for earnings and cash flow and assuming IDACORP meets those estimates, IDACORP's management anticipates recommending to the board of directors an additional increase to the quarterly dividend in September 2013 of at least ten percent. As of the date of this report, IDACORP's management's expectations for a September 2013 dividend increase recommendation have not changed.
For additional information relating to IDACORP and Idaho Power dividends, including additional restrictions on IDACORP's and Idaho Power's payment of dividends, see Note 6 - "Common Stock" to the condensed consolidated financial statements included in this report.
Contingencies and Proceedings IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. Certain legal or administrative proceedings to which IDACORP or Idaho Power are parties or are otherwise involved, and certain actual or potential legal claims pertaining to Idaho Power, are described in Note 9 - "Contingencies" to the condensed consolidated financial statements included in this report. Except where noted in Note 9, in many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.
Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of these regulations, but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.
59-------------------------------------------------------------------------------- Table of Contents Off-Balance Sheet Arrangements IDACORP's and Idaho Power's off-balance sheet arrangements have not changed materially from those reported in MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.
Impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted into law in July 2010. The Dodd-Frank Act establishes regulatory jurisdiction by the Commodity Futures Trading Commission (CFTC) and the SEC for certain swaps (which include a variety of derivative instruments) and the users of such swaps, and directed the CFTC and SEC to promulgate rules implementing a number of provisions of the Dodd-Frank Act. Under rules adopted pursuant to the Dodd-Frank Act, entities designated as "swap dealers" or "major swap participants" are subject to specified margin, collateral, mandatory exchange clearing, and reporting obligations. In April 2012, the SEC and the CFTC issued a joint final rule defining the terms "swap dealer" and "major swap participant." Idaho Power has determined that it is unlikely to be classified as either a swap dealer or a major swap participant under the rules, thus exempting Idaho Power from direct application of certain of the margin, collateral, and other burdensome and costly requirements of the rules. However, Idaho Power expects that entities classified as swap dealers or major swap participants will pass along their increased costs through higher prices and reductions in thresholds for posting collateral. Further, while Idaho Power believes that it may often rely upon an exemption from mandatory exchange clearing obligations contained in the rules, Idaho Power expects that the cost of entering into non-cleared swaps may increase and that required margin levels may be higher.
Idaho Power will also incur costs in connection with the reporting obligation under the rules. As of the date of this report Idaho Power expects that the financial and operational impact of the swap-related provisions of the Dodd-Frank Act and the CFTC's and SEC's associated rules will not be significant.
REGULATORY MATTERS Introduction As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers. Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT. Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, seeking to earn a return on investment where permitted by regulators. Idaho Power remains focused on communicating with regulators the necessity of investments to better serve its customers, the prudence of the costs incurred, and the importance of a reasonable return on investment for IDACORP's shareholders.
Idaho Power's need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, among other things, in-service dates of major capital investments and the timing of changes in major revenue and expense items. Idaho Power filed general rate cases in Idaho and Oregon during 2011, as well as a single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012, which have largely concluded. Idaho Power will continue to assess its need for general rate relief in consideration of the factors described above. Between general rate cases, Idaho Power relies upon power cost adjustment mechanisms, riders, and other mechanisms to reduce regulatory lag, which refers to the period of time between making an investment or incurring an expense and earning a return and recovering that investment or expense. Management's focus on constructive regulatory outcomes in 2011 and 2012 has been targeted largely at eliminating that regulatory lag.
60-------------------------------------------------------------------------------- Table of Contents Recent Regulatory Developments In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in Item 7 - MD&A and in Note 3 - "Regulatory Matters" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, refer to Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report for additional information and updates relating to Idaho Power's regulatory matters and recent regulatory filings and orders. The table below includes summary information on notable regulatory proceedings largely completed during 2012, and is followed by a summary of the more notable matters.
Estimated Annual Rate Impact Description Effective Date (millions)(1) Idaho: Langley Gulch power plant 7/1/2012 $ 58.1 Power cost adjustment (2) 6/1/2012 43.0 2011 general rate case settlement 1/1/2012 34.0 Boardman power plant cost recovery 6/1/2012 1.5 Fixed cost adjustment (2) 6/1/2012 1.2 Revenue sharing pursuant to January 2010 settlement 6/1/2012 agreement (2) (27.1 ) Depreciation rate for non-AMI meters 6/1/2012 (10.6 ) Depreciation update (other than non-AMI meters and 6/1/2012 (1.3 ) Boardman plant) Oregon: Langley Gulch power plant 10/1/2012 3.0 Oregon general rate case settlement 3/1/2012 1.8 Oregon annual power cost update (2) 6/1/2012 1.8 (1) The annual amount collected in rates is typically not recovered on a linear basis (i.e., 1/12th per month), and is instead recovered through Idaho Power's tiered rate structure, described above in this MD&A. Under a tiered rate structure, Idaho Power generally records revenues disproportionately during higher-load periods.
(2) The $43.0 million rate increase for the Idaho power cost adjustment, $1.2 million rate increase for the fixed cost adjustment, and $27.1 million rate decrease resulting from revenue sharing pursuant to the January 2010 settlement agreement are applicable only for the period from June 1, 2012 to May 31, 2013. Similarly, a portion of the $1.8 million rate increase from the Oregon annual power cost update is applicable only for a one-year period.
Idaho General Rate Case Settlement: In December 2011, the IPUC approved a settlement stipulation in Idaho Power's general rate case, which provided for a 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. New rates in conformity with the settlement became effective on January 1, 2012.
Oregon General Rate Case Settlement: On February 23, 2012, the OPUC approved a settlement stipulation in Idaho Power's Oregon general rate case. The settlement stipulation provides for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC is conducting a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger coal-fired power plant.
ADITC and Revenue Sharing Mechanism: In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows: • if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012; • if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.0 percent, and up to and including 10.5 percent, Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA adjustment; and 61-------------------------------------------------------------------------------- Table of Contents • if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customer rates through an offset in the pension balancing account, which would reduce the amount Idaho Power would collect from customers in rates.
The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. As of the date of this report, Idaho Power does not anticipate the need to amortize additional ADITC in 2012.
Langley Gulch Power Plant: On June 29, 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho- jurisdiction base rates, effective July 1, 2012, for recovery of Idaho Power's investment in the Langley Gulch power plant and associated costs. On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates for recovery of the investment and associated costs, with new rates in effect October 1, 2012. The plant became commercially available on June 29, 2012.
Power Cost Adjustment - Idaho: On April 13, 2012, Idaho Power made its annual PCA filing with the IPUC, requesting a $43 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The requested increase reflects increased projected power supply costs relative to the prior PCA year, due largely to an increase in mandated purchases of higher-cost, intermittent power under PURPA power purchase contracts. The IPUC issued an order on May 31, 2012 approving Idaho Power's application as filed. Previous annual PCA orders have resulted in a $40.4 million Idaho PCA rate decrease, effective June 1, 2011, and a $146.9 million Idaho PCA rate decrease, effective June 1, 2010. These prior PCA rate decreases were offset by increases in power supply costs in base rates and deferrals and amortization under the Idaho PCA mechanism, resulting in a relatively small impact on earnings.
Idaho Non-AMI Meter Depreciation: On April 27, 2012, the IPUC approved Idaho Power's February 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.
Change in Deferred Net Power Supply Costs Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual estimates of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table below summarizes the change in deferred net power supply costs during the nine months ended September 30, 2012.
Idaho Oregon(1) Total Balance at December 31, 2011 $ (13,121 ) $ 8,490 $ (4,631 ) Current period net power supply costs deferred 25,709 1,523 27,232 2011 revenue sharing liability applied to PCA true-up mechanism (2) (27,201 ) - (27,201 ) Prior amounts returned (recovered) through rates 21,993 (1,654 ) 20,339 SO2 allowance and renewable energy certificate (REC) sales (3,197 ) (156 ) (3,353 ) Interest and other (243 ) 511 268 Balance at September 30, 2012 $ 3,940 $ 8,714 $ 12,654 (1) Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $3 million). Deferrals are amortized sequentially.
(2) 2011 revenue sharing includes a $27.1 million liability together with carrying charges.
PURPA Power Purchases - Challenges and Proceedings Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from CSPP facilities. A key component of the PURPA power purchase contracts is the energy price contained within the agreements. Regulatory-mandated execution of PURPA agreements at times results in Idaho Power acquiring energy it does not need to serve loads, and at above wholesale market prices. Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates. In addition to increasing power purchase costs, integration of intermittent, non-dispatchable resources (such as wind power) into Idaho Power's portfolio creates a number of complex operational risks and challenges.
62-------------------------------------------------------------------------------- Table of Contents Idaho Power remains engaged in proceedings at the IPUC and OPUC relating to the determination of appropriate power purchase prices and other terms of PURPA power purchase agreements. Idaho Power is also engaged in proceedings at the FERC relating to its obligations under PURPA power purchase agreements. On January 31, 2012, Idaho Power submitted written testimony in its PURPA proceedings before the IPUC, in support of its request that, among other items, the IPUC (a) change the methodology used to establish power purchase prices for PURPA projects, (b) reduce the maximum authorized PURPA power purchase agreement term from the existing 20 years to a maximum of 5 years, and (c) authorize a curtailment strategy that would allow Idaho Power to optimize use of its cost-effective resources. Separately, on March 12, 2012, Idaho Power filed an application with the IPUC seeking a temporary stay of its obligation to enter into new PURPA power purchase agreements. While the IPUC denied Idaho Power's request for a stay in a March 22, 2012 order, the IPUC's order provided that the PURPA pricing methodologies in effect as of that date do not produce rates that are just and reasonable or in the public interest. As a result, the IPUC's order further provided that the IPUC would individually evaluate all contracts for PURPA projects over 100 kW entered into by Idaho Power and presented to the IPUC for approval, noting that FERC regulations require that the purchase price be just and reasonable to customers and in the public interest. Hearings in the IPUC proceedings were held during August 2012. Similar proceedings at the OPUC are also ongoing.
Developments with Large Industrial Customer In March 2009, the IPUC approved a September 2008 electric service agreement between Idaho Power and Hoku Materials, Inc. (Hoku), to provide electric service to Hoku's polysilicon production facility then under construction in Idaho. The initial term of the agreement was four years beginning December 1, 2009, with a maximum demand obligation during the initial term of 82 MW. In connection with an overdue invoice for electric service, in February 2012 Idaho Power, Hoku, and the IPUC Staff filed with the IPUC a settlement stipulation to amend the electric service agreement, and on March 15, 2012, the IPUC approved the stipulation revising the contract.
As a result of Hoku's failure to remain timely in payments under the revised agreement, Idaho Power terminated its provision of electric service under the revised agreement in May 2012. Idaho Power applied a $2 million deposit to Hoku's April, May, and June 2012 invoices under the revised agreement and fully exhausted the deposit required by the revised agreement. For full year 2012 and prior to termination of service, Idaho Power had anticipated contract payments of $5.4 million that are unaffected by the PCA mechanism and $6.8 million of revenues that are affected by and flow through the PCA mechanism, for a total of $12.2 million. Assuming that Hoku does not perform its obligations under the revised agreement during the remainder of 2012, Idaho Power estimates that it will only recognize $3.8 million of full year 2012 revenues that are unaffected by the PCA mechanism and $2.8 million of revenues that are affected by and flow through the PCA mechanism, for a total of $6.6 million for full year 2012. The ultimate impact of non-payment and associated decreases in revenue on 2012 net income would be tempered by a decrease in costs Idaho Power may have incurred in connection with the provision of service to Hoku and the impact of the PCA mechanism, likely resulting in a relatively small impact on full year net income.
2011 Integrated Resource Plan - Oregon Acknowledgment On May 21, 2012, the OPUC acknowledged Idaho Power's 2011 IRP, with conditions and exceptions. The OPUC directed Idaho Power to, among other things, include in its next IRP update an evaluation of environmental compliance costs for existing coal-fired plants. Idaho Power was directed to investigate whether there is "flexibility in the emerging environmental regulations" that would allow Idaho Power to "avoid early compliance costs by offering to shut down individual units prior to the end of their useful lives." The order also directed Idaho Power to conduct further plant-specific analysis to determine whether this trade-off would be in the ratepayers' interest. Idaho Power is currently preparing its 2013 IRP.
Hydroelectric Projects - Relicensing and Upgrades Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service.
Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. HCC relicensing costs of $156 million were included in construction work in progress at September 30, 2012. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho-jurisdiction rates approximately $6.5 million annually ($10.7 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.
Item 7 - MD&A - "Regulatory Matters" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011 contains a discussion of the status of relicensing efforts and other projects for the HCC, Swan Falls Project, and Shoshone Falls facility. Set forth below is an update on the status of those projects relative to that prior discussion.
63-------------------------------------------------------------------------------- Table of Contents Swan Falls Project - On September 28, 2012, the FERC issued Idaho Power a 30-year license for continued operation of the Swan Falls hydroelectric project.
Idaho Power is evaluating the terms and conditions of the license, but as of the date of this report believes that operational changes will be modest and that the capital investments it will be required to make under the terms of the license will be within the range Idaho Power expected.
Shoshone Falls Expansion - On July 1, 2010, the FERC amended the license for the Shoshone Falls project to expand its generating capacity from 12.5 MW to approximately 61 MW. The amended license has an expiration date of 2034, but provides that the license will be extended to 2044 following completion of the proposed generation capacity expansion project. On May 1, 2012, FERC granted Idaho Power a two-year schedule extension to complete construction of the expansion. As a result, the new deadline for construction completion is July 1, 2017. Subject to the outcome of additional cost studies and analysis and the results of further engineering and design work, Idaho Power will make a final determination whether to proceed with the expansion project. To mitigate the regulatory risk associated with the project, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC prior to commencement of construction.
ENVIRONMENTAL MATTERS Overview Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment.
Current and pending environmental legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards, mercury and other emissions, hazardous wastes, and polychlorinated biphenyls. In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief, and other sanctions. These laws and regulations are administered by the U.S.
Environmental Protection Agency (EPA) and state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately need to be resolved by the courts.
Additionally, the FERC licenses issued for Idaho Power's hydroelectric generating plants impose numerous environmental requirements, such as aeration of water discharged through turbines to meet dissolved gas and temperature standards in the tail waters downstream from the plants. Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies.
Also, Idaho Power co-owns three coal-fired power plants and owns three natural gas-fired combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation. These regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements cannot be fully recovered in rates on a timely basis or at all.
Operation of Idaho Power's jointly-owned coal-fired power plants is subject to a broad range of federal, state, and local environmental laws and regulations, both pending and enacted. Idaho Power expects that these laws and regulations, which will continue to increase the cost of operating coal-fired power plants and constructing new facilities, will necessitate installation of additional pollution control devices at existing generating plants, or result in Idaho Power discontinuing operation of certain coal-fired plants where operation becomes uneconomical. In connection with its IRP process, Idaho Power has been conducting cost studies and scenario analysis to assess these investment decisions, using a range of fuel pricing assumptions, plant upgrade and retirement costs, environmental regulation assumptions, replacement costs, and other factors in that assessment. Idaho Power plans to publish the results of its most recent analysis with its 2011 IRP update to be filed with the OPUC in November 2012, and invites interested parties to review and comment on the results of the analysis.
Included below is a summary of notable developments in environmental, climate change, sustainability, and related issues impacting Idaho Power since the discussion of these and other matters included in Part II, Item 7 - "MD&A - Environmental Issues" and "MD&A - Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.
Environmental Sustainability Initiatives Extension of CO2 Intensity Reduction Goal While there is currently no national mandatory greenhouse gas reduction requirement, Idaho Power continues to prepare for potential legislative and/or regulatory restrictions on emissions in order to help reduce the costs of complying with such restrictions on its customers. To that end, Idaho Power is engaged in voluntary greenhouse gas emission intensity reduction efforts. In September 2009, IDACORP's and Idaho Power's boards of directors approved guidelines that established a goal to 64-------------------------------------------------------------------------------- Table of Contents reduce Idaho Power's resource portfolio's average CO2 emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO2 emission intensity of 1,194 lbs CO2/MWh. Idaho Power's estimated CO2 emission intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was 672, 1,051, and 1,004 lbs/MWh for 2011, 2010, and 2009 respectively.
As of the date of this report, Idaho Power is on-track to exceed the CO2 emission intensity reduction goal it established in 2009. The combination of effective utilization of hydroelectric projects, above average stream flows during 2011, reduced usage of coal-fired facilities, and addition of the Langley Gulch natural gas-fired power plant have positioned the company to extend its CO2 intensity reduction goal period for an additional two years, targeting an average reduction of 10 to 15 percent below its 2005 levels for the entire 2010 through 2015 time period. Idaho Power management plans to recommend to its board of directors that the board approve the extension of the intensity reduction goal.
Wind Integration Study Since 2010, Idaho Power has seen an unprecedented increase in the number of wind power developments seeking to enter into power purchase arrangements with Idaho Power pursuant to PURPA. As of September 30, 2012, Idaho Power had CSPP wind contracts with on-line projects totaling 537 MW of nameplate capacity, as well as an additional 101 MW nameplate capacity from the Elkhorn Valley non-CSPP wind project.
As described above in this MD&A under "PURPA Power Purchases - Challenges and Proceedings," Idaho Power has been involved in proceedings at the IPUC, OPUC, and FERC to determine the appropriate power purchase price and other terms of PURPA agreements, as to-date those terms have resulted in a significant increases in the number of PURPA projects seeking contracts with Idaho Power and associated escalation in power purchase costs to the detriment of Idaho Power's customers. Beyond the direct adverse impact on customer rates are the operational challenges imposed by power purchases mandated by PURPA. An abundance of wind power during times when Idaho Power has available lower-cost resources available to meet load demands has an impact on the operation of Idaho Power's other generation plants, system reliability, wear and tear on dispatchable generators from rapidly adjusting output to balance loads, and power supply costs. When forecast wind or other intermittent resources do not materialize, Idaho Power must have dispatchable resources on stand-by to ensure the continued delivery of reliable power. The quantity of wind generation that Idaho Power can integrate depends largely on customer load. During times of markedly low customer demand, the system of dispatchable generators often cannot provide the stand-by capacity for balancing wind without causing an over-generation condition. System hydro regulations, available reservoir storage volume, dispatched resources, FERC restrictions, environmental regulations, and numerous other conditions also influence Idaho Power's ability to integrate wind onto its system.
In response to the operational challenges associated with integrating wind, and the recognition that these challenges will become even more pronounced as the volume of intermittent resources in Idaho Power's portfolio increases, Idaho Power continues efforts to better understand the effects of wind on power system operation. As part of these efforts, Idaho Power issued its first wind integration study in 2007, and beginning in 2011 Idaho Power launched its second, and more comprehensive, wind integration study. The goal of the most recent study is to assess the costs incurred in modifying operations of dispatchable generating resources to allow them to respond to the variable and uncertain energy supplied by wind generators and deliver reliable energy to customers. Additionally, the study aims to provide insight on the maximum amount of wind generation Idaho Power's system can accommodate without impacting reliability. Idaho Power has committed considerable resources to the study, including working with an independent consultant, utility industry peers, and interested parties, and has also held public workshops. Idaho Power intends to release the details of the report publicly and invites interested parties to provide their feedback. Further in response to the integration challenges, Idaho Power has implemented an internally developed wind forecasting system, in recognition that cost intensive modifications to operations intended to integrate wind are reduced, though not eliminated, with improved wind production forecasting.
As outlined in its inaugural sustainability report issued in May 2011, Idaho Power's goal is to maintain a balanced set of resources, including through its low-cost hydro, natural gas, and coal fleet, as well as through renewable energy and purchased power. In seeking this balance, Idaho Power does and will continue to take into consideration not only economic considerations, but also environmental concerns, including the impact of any dispatch and resource decisions on Idaho Power's carbon emission reduction goals.
65-------------------------------------------------------------------------------- Table of Contents Environmental Regulation Mercury and Air Toxics Standards (MATS): In April 2010, the U.S. District Court for the District of Columbia approved, by consent decree, a timetable that required the EPA to finalize a standard to control mercury emissions from coal-fired power plants by November 2011. In March 2011, the EPA released the proposed MATS to control emissions of mercury and other hazardous air pollutants (HAPs) from coal- and oil-fired electric utility steam generating units (EGUs) under the federal Clean Air Act (CAA). In the same notice, the EPA further proposed to revise the new source performance standards (NSPS) for fossil fuel-fired EGUs. Both the proposed HAPs regulation and the associated NSPS revisions were finalized on February 16, 2012. The regulation imposes maximum achievable control technology and NSPS on all coal-fired EGUs and replaces the former Clean Air Mercury Rule. Specifically, the regulation sets numeric emission limitations on coal-fired EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrogen chloride, and mercury. In addition, the regulation imposes a work practice standard for organic HAPs, including dioxins and furans. For the revised NSPS, for EGUs commencing construction of a new source after publication of the final rule, the EPA has established amended emission limitations for particulate matter, sulfur dioxide, and nitrogen oxides. Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy generating plants. However, Idaho Power has reviewed the final rule and is in the process of determining how to meet these regulations at the Bridger, Boardman, and Valmy generating plants. The compliance deadline for the new MATS could be as early as 2015, though the current federal Administration has suggested that a one-year extension may be available for utilities where justified.
National Ambient Air Quality Standards (NAAQS) for NOx: In February 2010, the EPA revised the NAAQS for NO2, establishing a one-hour standard at a level of 100 parts per billion. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as "unclassifiable/attainment" for NO2. The EPA indicated it will review the designations after 2015, when three years of air quality monitoring data are available, and may formally designate the counties as attainment or non-attainment for NO2. A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more of its plants. As the designations have not yet been finalized, as of the date of this report Idaho Power is unable to predict the impact of the NAAQS for NO2 on its operations. However, the costs of installation and implementation of any additional pollution reduction technology could be substantial.
NAAQS for Particulate Matter: On June 29, 2012, the EPA published proposed revisions to the primary and secondary NAAQS for fine particulate matter (PM2.5). The EPA also proposed revisions to the prevention of significant deterioration permitting program with respect to the proposed NAAQS revisions.
The EPA has stated that it plans to finalize the air quality standards by December 2012. The EPA's proposed primary standard for fine particles was between 12 and 13 micrograms per cubic meter (µg/m3), calculated as a three-year average. The EPA proposed to retain the exiting 24-hour primary standard for fine particulate matter at 35 µg/m3. The EPA proposed to remain unchanged the secondary standards for PM2.5 and would be identical to the primary standards.
Once finalized, the revisions to the NAAQS would trigger a process under which states will make recommendation to the EPA regarding designations of attainment or non-attainment. States also will be required to review, modify, and supplement their existing state implementation plans (SIP), which could require the installation of additional controls and requirements for Idaho Power's coal-fired generation plants, depending on the level ultimately finalized. The revised NAAQS would also have an impact on the applicable air permitting requirements for new and modified facilities. The EPA has stated that it plans to issue nonattainment designations by late 2014, with states having until 2020 to comply with the standards. As applicable rules have not yet been finalized and adopted, as of the date of this report Idaho Power is unable to predict the potential financial or operational impact of the proposed NAAQS for fine particulate matter.
NSPS for Greenhouse Gas Emissions for New EGUs: In March 2012, the EPA proposed NSPS limiting CO2 emissions from new fossil fuel-fired power plants. The proposed requirements, which are limited to new sources, would require new fossil fuel-fired EGUs greater than 25 MW to meet an output-based standard of 1,000 pounds of CO2 per MWh. The EPA did not propose standards of performance for existing EGUs whose CO2 emissions increase as a result of installation of pollution controls for conventional pollutants. While Idaho Power does not expect the new NSPS to impact its existing generation facilities, the new rules, if enacted, would impact the cost effectiveness of developing new EGUs.
Clean Air Act - Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and the Boardman plant. Under the CAA, states are required to develop a SIP to meet various air quality requirements and submit them to the EPA for approval. The CAA provides that if the EPA deems a SIP submittal to be incomplete or "unapprovable," then the EPA will promulgate a federal implementation plan (FIP) to fill the deemed regulatory gap. In May 2012, the EPA proposed to partially reject Wyoming's regional haze SIP, submitted in January 2011, for NOx reduction at the Jim Bridger plant, instead proposing to substitute the 66-------------------------------------------------------------------------------- Table of Contents EPA's own RH BART determination and FIP. The EPA's primary proposal would result in an acceleration of the installation of selective catalytic reduction (SCR) additions at Bridger Units 1 and 2 to within five years after the FIP, or a SIP revised to be consistent with the proposed FIP, is adopted by the EPA. The EPA has stated that it plans to adopt the FIP, or approve the revised Wyoming SIP, by late 2012. The EPA recognized that this accelerated schedule may create a hardship for the owners of the Jim Bridger plant, including Idaho Power and its customers, and has requested the submission of comments on whether the Wyoming schedule that would not require installation of the SCR on Bridger Units 1 and 2 until 2021 and 2022, respectively, is more appropriate. In August 2012, Idaho Power and PacifiCorp, among other interested parties, submitted comments to the EPA in support of the Wyoming SIP and requesting that the SIP be approved without amendment.
Clean Water Act Section 316(b): In March 2011, the EPA issued a proposed rule that would establish requirements under Section 316(b) of the federal Clean Water Act for all existing power generating facilities and existing manufacturing and industrial facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. The proposed rules would establish national requirements applicable to the location, design, construction, and capacity of cooling water intake structures at these facilities by setting requirements that reflect the best technology available for minimizing adverse environmental impact. In June 2012, the EPA released new data, requested further public comment, and announced it plans to finalize the cooling water intake structures rule by June 2013. Based on the qualification criteria, Idaho Power expects that the new requirements would apply to the Jim Bridger plant but is unable to determine the potential increased costs that may result until final rules are issued and it has performed cost studies.
Endangered Species Endangered Species Act -- Bliss and Lower Salmon Falls Projects: As part of a settlement agreement for the current license, Idaho Power has finalized a snail protection plan for the Bliss and Lower Salmon Falls projects in cooperation with the U.S. Fish and Wildlife Service (USFWS). Idaho Power has filed applications with the FERC to amend the licenses for the projects that will maintain operating flexibility at both projects for the remainder of their licenses. The FERC requested formal consultation with the USFWS regarding the license amendments in July 2012. The ESA Section 7 consultation will include two listed snails, the Bliss Rapids snail and the Snake River physa snail. Idaho Power has been working closely with USFWS to develop the necessary biological information for timely completion of the consultation.
Renewable Energy Contracts and Credits CSPP Contracts: Idaho Power purchases wind power from both CSPP and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of September 30, 2012, Idaho Power had contracts to purchase energy from 26 on-line CSPP wind power projects with a combined nameplate rating of 537 MW. At that date, Idaho Power also had signed, public utility commission-approved contracts to purchase energy from one CSPP wind project with a combined nameplate rating of 40 MW. This project is expected to be on-line in December 2012. In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other renewable generation sources, such as biomass, solar, and small hydroelectric projects. As of September 30, 2012, Idaho Power had 20 MW of solar power generation under contract for purchase. As of September 30, 2012, Idaho Power had the number and nameplate capacity of signed CSPP-related agreements with terms ranging from one to 35 years set forth in the table below.
Number of CSPP Nameplate Capacity Status Contracts (MW) On-line as of September 30, 2012 102 739 Contracted and projected to come on-line by year-end 2014 7 92 Total 109 831 In August 2012, Idaho Power entered into a settlement stipulation with the developer of wind projects with a planned aggregate nameplate capacity of 116 MW, in connection with Idaho Power's contention that the developer had failed to complete the project in advance of the scheduled operation date required by the power purchase agreements entered into between Idaho Power and the wind projects. The settlement stipulation, which was approved by the IPUC in August 2012, provides that Idaho Power will return to the project developer the letters of credit it held as delay security for the projects, and that the power purchase agreements would be terminated.
REC Sales: Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to Idaho customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. Idaho Power filed a REC 67-------------------------------------------------------------------------------- Table of Contents Management Plan with the IPUC in December 2009 to address its treatment of future RECs. Under the REC Management Plan, Idaho Power is selling its near-term RECs while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future renewable portfolio standards. For the nine months ended September 30, 2012 and 2011, Idaho Power's REC sales were approximately $4 million and $5 million, respectively. Ordinarily, Idaho Power does not receive the RECs associated with PURPA projects. However, Idaho Power is engaged in proceedings at the IPUC relating to ownership of RECs associated with PURPA projects.
OTHER MATTERS Critical Accounting Policies and Estimates IDACORP's and Idaho Power's discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles. The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and Idaho Power evaluate these estimates, including those estimates related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, unbilled revenue, and bad debt. These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.
IDACORP's and Idaho Power's critical accounting policies are reviewed by the audit committee of the boards of directors. These policies have not changed materially from the discussion of those policies included under "Critical Accounting Policies and Estimates" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.
Recently Issued Accounting Pronouncements There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition.
Back To NFVZone's Homepage