|
|
 | | | |
- close
- close
- close
- close
Westar Energy 10-Q 2011 Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q
For the quarterly period ended June 30, 2011 OR
For the transition period from to Commission File Number 1-3523 WESTAR ENERGY, INC. (Exact name of registrant as specified in its charter)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act). Check one: Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Table of ContentsTABLE OF CONTENTS
2
Table of ContentsGLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.
3
Table of ContentsFORWARD-LOOKING STATEMENTS Certain matters discussed in this Form 10-Q are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning matters such as, but not limited to:
What happens in each case could vary materially from what we expect because of such things as:
4
Table of Contents
These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with our 2010 Form 10-K. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our consolidated financial results may be included in our 2010 Form 10-K. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.
5
Table of Contents
WESTAR ENERGY, INC. (Dollars in Thousands, Except Par Values) (Unaudited)
The accompanying notes are an integral part of these condensed consolidated financial statements.
6
Table of ContentsWESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts) (Unaudited)
The accompanying notes are an integral part of these condensed consolidated financial statements.
7
Table of ContentsWESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts) (Unaudited)
The accompanying notes are an integral part of these condensed consolidated financial statements.
8
Table of ContentsWESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)
The accompanying notes are an integral part of these condensed consolidated financial statements.
9
Table of ContentsWESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Dollars in Thousands) (Unaudited)
The accompanying notes are an integral part of these condensed consolidated financial statements.
10
Table of ContentsWESTAR ENERGY, INC. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. DESCRIPTION OF BUSINESS We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 688,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single operating segment. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the consolidated financial statements, have been included. The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2010 Form 10-K. Use of Management’s Estimates When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, valuation of investments, valuation of our energy marketing portfolio, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and other post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2011, are not necessarily indicative of the results to be expected for the full year.
11
Table of ContentsAllowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:
Earnings Per Share We have participating securities related to unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends as declared on an equal basis with common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). Under the two-class method, we reduce net income attributable to common stock by the amount of dividends declared in the current period. We allocate the remaining earnings to common stock and RSUs to the extent that each security may share in earnings as if all of the earnings for the period had been distributed. We determine the total earnings allocated to each security by adding together the amount allocated for dividends and the amount allocated for a participation feature. To compute basic EPS, we divide the earnings allocated to common stock by the weighted average equivalent common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from our forward sale agreements, RSUs that do not have nonforfeitable rights to dividend equivalents and stock options. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.
12
Table of ContentsThe following table reconciles our basic and diluted EPS from net income.
Supplemental Cash Flow Information
13
Table of Contents3. FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING SECURITIES, ENERGY MARKETING AND RISK MANAGEMENT Values of Financial and Derivative Instruments GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of fair value assets and liabilities within the fair value hierarchy levels. The three levels of the hierarchy and examples are as follows:
We record cash and cash equivalents, short-term borrowings and variable rate debt on our consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed-rate debt based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value. All of our level 2 investments, whether in the nuclear decommissioning trust (NDT) or our trading securities portfolio, are held in investment funds that are measured using daily net asset values as reported by the fund managers. In addition, we maintain certain level 3 investments in private equity and real estate securities that require significant unobservable market information to measure the fair value of the investments. The fair value of private equity investments is measured by utilizing both market- and income-based models, public company comparables, at cost or at the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. To measure the fair value of real estate securities we use a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity. Energy marketing contracts can be exchange-traded or traded over-the-counter (OTC). Fair value measurements of exchange-traded contracts typically utilize quoted prices in active markets. OTC contracts are valued using market transactions and other market evidence whenever possible, including market-based inputs to models, model calibration to market clearing transactions or alternative pricing sources with reasonable levels of price transparency. Valuation models require a variety of inputs, including contractual terms, market prices, yield curves, credit curves, nonperformance risk, measures of volatility and correlations of such inputs. Certain OTC contracts trade in less liquid markets with limited pricing information and the determination of fair value for these derivatives is inherently more subjective. In these situations, estimates by management are a significant input. See “—Recurring Fair Value Measurements” and “—Derivative Instruments” below for additional information.
14
Table of ContentsWe measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our financial instruments as of June 30, 2011, and December 31, 2010.
15
Table of ContentsRecurring Fair Value Measurements The following table provides the amounts and their corresponding level of hierarchy for our assets and liabilities that are measured at fair value.
We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of June 30, 2011, we had recorded $0.1 million for our right to reclaim cash collateral and $1.0 million for our obligation to return cash collateral. As of December 31, 2010, we had no right to reclaim cash collateral and had recorded $0.7 million for our obligation to return cash collateral.
16
Table of ContentsThe following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and six months ended June 30, 2011.
17
Table of ContentsThe following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and six months ended June 30, 2010.
18
Table of ContentsA portion of the gains and losses contributing to changes in net assets in the above table is unrealized. The following tables summarize the unrealized gains and losses we recorded on our consolidated financial statements during the three and six months ended June 30, 2011 and 2010, attributed to level 3 assets and liabilities.
19
Table of ContentsSome of our investments in the NDT and all of our trading securities do not have readily determinable fair values and are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides additional information on these investments.
Derivative Instruments Cash Flow Hedges In 2010, we entered into treasury yield hedge transactions for a total notional amount of $100.0 million in an attempt to manage our interest rate risk associated with a future anticipated issuance of fixed-rate debt, which is probable to occur within 18 months of the initial treasury yield hedge transaction date. Such transactions are designated and qualify as cash flow hedges and are measured at fair value by estimating the net present value of a series of payments using market-based models with observable inputs, such as the spread between the 30-year U.S. Treasury bill yield and the contracted, fixed yield. As a result of regulatory accounting treatment, we report the effective portion of the gain or loss on these derivative instruments as a regulatory liability or regulatory asset and will amortize such amounts to interest expense over the life of the related debt. We record hedge ineffectiveness gains in other income and hedge ineffectiveness losses in other expense on our consolidated statements of income. As of June 30, 2011, and December 31, 2010, the fair value of the treasury yield hedge transactions was $6.5 million and $7.7 million, respectively, which we recorded in other current assets and other assets, respectively, on our consolidated balance sheets. We also recorded these same amounts in current regulatory liabilities and long-term regulatory liabilities, respectively, on our consolidated balance sheets to reflect the effective portion of the gains on these transactions as of June 30, 2011, and December 31, 2010. Commodity Contracts We engage in both financial and physical trading with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We trade electricity and other energy-related products using a variety of financial instruments, including futures contracts, options, swaps and physical commodity contracts.
20
Table of ContentsWe classify these commodity derivative instruments as energy marketing contracts on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities. With the exception of certain fuel supply and electricity contracts, which we record as regulatory assets or regulatory liabilities, we include the change in the fair value of energy marketing contracts in revenues on our consolidated statements of income. The following table presents the fair value of commodity derivative instruments reflected on our consolidated balance sheets. Commodity Derivatives Not Designated as Hedging Instruments as of June 30, 2011
Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 2010
The following table presents how changes in the fair value of commodity derivative instruments affected our consolidated financial statements for the three and six months ended June 30, 2011 and 2010.
As of June 30, 2011, and December 31, 2010, we had under contract the following commodity derivatives.
21
Table of ContentsNet open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have net open positions, we are exposed to the risk that changing market prices could have a material adverse impact on our consolidated financial results. Energy Marketing Activities Within our energy trading portfolio, we may establish certain positions intended to economically hedge a portion of physical sale or purchase contracts and we may enter into certain positions attempting to take advantage of market trends and conditions. We use the term economic hedge to mean a strategy intended to manage risks of volatility in prices or rate movements on selected assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to offset the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. Price Risk We use various types of fuel, including coal, natural gas, uranium, diesel and oil, to operate our plants and purchase power to meet customer demand. Our prices, consolidated financial results and cash flows are exposed to market risks from commodity price changes for electricity and other energy-related products and interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to these market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes. Interest Rate Risk We have entered into fixed and variable rate debt obligations. We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps. Credit Risk In addition to commodity price risk, we are exposed to credit risks associated with the financial condition of counterparties, product location (basis) pricing differentials, physical liquidity constraints and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties intended to reduce our overall credit risk exposure to a level we deem acceptable and include the right to offset derivative assets and liabilities by counterparty. We have derivative instruments with commodity exchanges and other counterparties that do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of June 30, 2011, and December 31, 2010, was $6.6 million and $1.6 million, respectively, for which we had posted $1.6 million of collateral, including independent amounts, as of June 30, 2011, and no collateral as of December 31, 2010. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2011, and December 31, 2010, we would have been required to provide to our counterparties $2.0 million and $1.6 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.
22
Table of Contents4. FINANCIAL INVESTMENTS We report some of our investments in debt and equity securities at fair value and use the specific identification method to determine their realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below. Trading Securities We have equity and debt investments in a trust used to fund retirement benefits that we classify as trading securities. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. During the three and six months ended June 30, 2011, we recorded gains on these securities of $0.6 million and $2.5 million, respectively. We recorded unrealized losses of $2.6 million and $1.1 million, respectively, during the three and six months ended June 30, 2010. Available-for-Sale Securities We hold investments in equity, debt and real estate securities in a trust fund for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2011, and December 31, 2010. At June 30, 2011, investments in the NDT fund were allocated 42% to domestic equity, 20% to international equity, 16% to core bonds, 7% to high-yield bonds, 4% to emerging market bonds, 6% to combined debt/equity funds, 2% to real estate securities and 3% to cash and cash equivalents. The core bond fund has a requirement that at least 80% of funds are invested in investment grade U.S. corporate and government fixed income securities, including mortgage-backed securities. As of June 30, 2011, the fair value of available-for-sale debt securities in the core, high-yield and emerging market bond funds was $36.8 million. As of June 30, 2011, we had not invested in debt securities outside of investment funds. Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $0.3 million and $1.3 million, respectively, during the three and six months ended June 30, 2011. During the three and six months ended June 30, 2010, we realized gains of $12.6 million and $13.5 million, respectively, on these securities. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.
23
Table of ContentsThe following table presents the costs and fair values of investments in the NDT fund as of June 30, 2011, and December 31, 2010.
The following table presents the fair value and gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of June 30, 2011, and December 31, 2010.
24
Table of Contents5. RATE MATTERS AND REGULATION KCC Proceedings On May 27, 2011, the Kansas Corporation Commission (KCC) issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2010. The new prices were effective June 1, 2011, and are expected to increase our annual retail revenues by approximately $10.4 million. We have a 50% interest in La Cygne Generating Station (La Cygne). Kansas City Power & Light Company (KCPL) is a 50% joint owner and the operator of the plant. On February 23, 2011, KCPL filed an application requesting that the KCC predetermine the ratemaking principles for and determine the appropriateness of approximately $1.2 billion of environmental upgrades proposed for La Cygne to comply with environmental regulations. We intervened in the proceeding. The KCC ruled in the May 27, 2011, order noted above that it would not approve recovery of our share of expenditures for environmental upgrades at La Cygne through the price adjustment approved in the order until the KCC’s investigation and analysis of the proposed upgrades is completed. In the KCPL proceeding, KCPL, KCC Staff and we agree that the La Cygne environmental upgrades should be completed as described in the application. Technical hearings on this matter concluded in mid July 2011 and the KCC is expected to issue a final order in late August 2011. If we are unable to collect the costs of La Cygne environmental upgrades through the environmental cost recovery rider (ECRR), we will experience an increase in the time between making these investments and having the costs reflected in the prices we charge our customers. This could also impact the amount we charge customers, and our plans to execute this project in part or whole could change. If the KCC were to rule against completing the environmental upgrades at La Cygne, we would not be able to comply with the aforementioned environmental regulations, which could ultimately result in shutting the plant down and requiring us to procure more expensive sources of power. On April 11, 2011, the KCC issued an order allowing us to adjust our prices, subject to final KCC review, to include updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective April 14, 2011, and are expected to increase our annual retail revenues by $17.4 million. We expect the KCC to issue a final order on our request in the third quarter of 2011. FERC Proceedings Our transmission formula rate that includes projected 2011 transmission capital expenditures and operating costs became effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above. 6. SHORT-TERM DEBT Westar Energy has a $730.0 million revolving credit facility with a syndicate of banks that terminates on March 17, 2012. As of June 30, 2011, $471.0 million had been borrowed and an additional $15.6 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2010, $226.7 million had been borrowed and an additional $21.5 million of letters of credit had been issued under this revolving credit facility. In February 2011, Westar Energy entered into a new revolving credit facility with a similar syndicate of banks for an additional $270.0 million. The commitments under this facility terminate on February 18, 2015. As of June 30, 2011, Westar Energy had neither borrowed monies nor issued letters of credit under this revolving credit facility.
25
Table of Contents7. TAXES We recorded income tax expense of $19.6 million with an effective tax rate of 30% for the three months ended June 30, 2011, and income tax expense of $21.2 million with an effective income tax rate of 28% for the same period of 2010; and income tax expense of $33.1 million with an effective income tax rate of 30% for the six months ended June 30, 2011, and income tax expense of $35.0 million with an effective income tax rate of 29% for the same period of 2010. The increases in the effective income tax rates for the three and six months ended June 30, 2011, were due primarily to decreases in non-taxable income from corporate-owned life insurance in 2011 compared to 2010 and the settlement of the Internal Revenue Service’s examination of the 2009 tax year in the second quarter of 2011. In 2010, we established a valuation allowance of $51.9 million against the unused state investment tax credits of $116.2 million. This valuation allowance was reversed during the second quarter of 2011 due to a state law change which extended the state investment tax credit carryforward period from 10 to 16 years. At June 30, 2011, and December 31, 2010, our liability for unrecognized income tax benefits was $2.8 million and $1.9 million, respectively. The net increase in the liability for unrecognized income tax benefits was largely attributable to tax positions taken with respect to the capitalization of plant related expenditures. We do not expect any significant changes in this liability in the next 12 months. As of June 30, 2011, and December 31, 2010, we had $0.4 million accrued for interest on our liability related to unrecognized income tax benefits. We accrued no penalties at either June 30, 2011, or December 31, 2010. As of June 30, 2011, and December 31, 2010, we had recorded $3.6 million for probable assessments of taxes other than income taxes. 8. COMMITMENTS AND CONTINGENCIES Federal Clean Air Act We must comply with the Federal Clean Air Act, state laws and implementing regulations that impose, among other things, limitations on emissions generated during our operations, including sulfur dioxide (SO2), particulate matter, nitrogen oxides (NOx) and mercury. In addition, we must comply with the provisions of the Federal Clean Air Act Amendments of 1990 that require reductions in SO2 and NOx. Emissions from our generating facilities, including particulate matter, SO2 and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE), we are required to install and maintain controls to reduce emissions found to cause or contribute to regional haze. Under the Federal Clean Air Act, the Environmental Protection Agency (EPA) sets National Ambient Air Quality Standards (NAAQS) for six criteria emissions considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO2. We are currently evaluating what impact this could have on our operations. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.
26
Table of ContentsEnvironmental Projects We will continue to make significant capital expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could change materially depending on the timing and nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce the net production, reliability and availability of the plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments. The ECRR allows for the more timely inclusion in retail prices of the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our prices to recognize increased operating and maintenance costs, however, we must file a general rate case with the KCC. Moreover, as previously discussed, presently we are not allowed to use the ECRR to recover costs associated with proposed environmental upgrades at La Cygne while the KCC is reviewing the proposed upgrades. Upon the conclusion of that review, we expect to learn whether or not we can reinstate the ECRR for La Cygne. Air Emissions In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which requires 27 states, including Kansas, to further reduce power plant emissions of SO2 and NOx. Under CSAPR, reductions in annual SO2 and NOx emissions are required to begin January 1, 2012, with further reductions required beginning January 1, 2014. The EPA is issuing federal implementation plans for each state covered by CSAPR, but is allowing states to submit their own implementation plans starting as early as 2013. There are a number of uncertainties relating to CSAPR, including how Kansas will implement the requirements. In addition, the implementation timeline for CSAPR is abbreviated in comparison to EPA precedent for regulations of similar magnitude. To comply with the rule on January 1, 2012, we expect that we must modify the way in which we use our power plants, purchase power or purchase emission allowances, as there is insufficient time to install equipment needed to reduce emissions to the levels required by the rule. We could incur substantial fines and penalties for noncompliance. We cannot yet determine the impact this new rule will have on our operations or consolidated financial results, but it could be material. Greenhouse Gases Under EPA regulations finalized in May 2010, known as the tailoring rule, the EPA began regulating greenhouse gas (GHG) emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two Federal Clean Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), will be required to implement best available control technology (BACT). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these new regulations on our operations and consolidated financial results, but we believe the cost of compliance with new regulations could be material. Renewable Energy Standard In May 2009, Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. In years 2011 through 2015 net renewable generation capacity must be 10% of the average peak demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. We have worked with third parties to develop approximately 300 MW of qualifying renewable generation facilities which, together with the use of renewable energy credits, we expect will allow us to meet the 2011 requirement. On December 14, 2010, we announced that we reached two separate agreements with third parties to purchase under 20-year supply contracts the renewable energy produced from approximately 370 MW of renewable generation beginning in late 2012. The KCC approved the agreements and the associated cost recovery in an order dated May 9, 2011. We expect these agreements, along with our prior development of renewable generation facilities, will satisfy our net renewable generation requirement through 2015 and contribute toward meeting the increased requirement beginning in 2016. Manufactured Gas Sites We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas. We and KDHE entered into a consent agreement governing all future work at these sites. Under terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK Inc. (ONEOK), ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million.
27
Table of ContentsEPA Lawsuit In March 2010, the U.S. District Court in the District of Kansas approved a settlement agreement that we entered into with the parties of a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at JEC violated certain requirements of the EPA’s New Source Review program, which requires companies to obtain permits and, if necessary, install control equipment to address emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions. As part of the settlement agreement, in 2009 we recorded $1.0 million for environmental mitigation projects that will be owned by a qualifying third party and a $3.0 million civil penalty. We will also invest $5.0 million over six years in environmental mitigation projects that we will own. In addition, we will install a selective catalytic reduction (SCR) on one of the three JEC coal units by the end of 2014. We estimate the cost of this to be approximately $240.0 million. This amount could change materially depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, we may have to install an SCR on another JEC unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge customers. FERC Investigation A non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008 remains pending. In May 2009, FERC staff alleged that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff first alleged we received $14.3 million of unjust profits through such activities. We sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. Based on our response, FERC staff substantially revised downward its preliminary conclusions to allege that we received $3.0 million of unjust profits and failed to pay $3.2 million to the SPP for transmission service. In March 2010, we sent a response to FERC staff disputing its revised conclusions. We continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are unable to predict the outcome of this investigation or its impact on our consolidated financial results, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and could potentially alter the manner in which we are permitted to buy and sell energy and use transmission service. 9. LEGAL PROCEEDINGS In late 2002, one of our former executive officers resigned from his position and another executive officer was placed on administrative leave from his position. Following the completion of an investigation and the publication of a report prepared by a special committee of our board of directors, our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment and the publication of the report of the special committee. The arbitration was stayed in August 2004 pending final resolution of criminal charges filed against them in U.S. District Court in the District of Kansas. In August 2010, these criminal charges were dismissed and subsequently the stay of the arbitration was lifted. As of December 31, 2010, we had accrued liabilities of $80.6 million for compensation not yet paid to them and $8.3 million for legal fees and expenses they had incurred. In May 2011, we reached an agreement with Douglas T. Lake, one of the former executive officers, settling all contractual obligations and other claims. Pursuant to the agreement, we paid him approximately $21.0 million and we paid approximately $5.3 million for his legal fees and expenses. The accruals were reduced by the same amounts. As of June 30, 2011, we had accrued liabilities of $60.7 million for compensation not yet paid to David C. Wittig, the other former executive officer, and $3.1 million for his legal fees and expenses. In July 2011, we reached an agreement with Mr. Wittig settling all contractual obligations and other claims and providing for payments totaling approximately $36.0 million, the release of deferred stock for compensation shares and the payment of $3.1 million for his legal fees and expenses. The settlement with Mr. Wittig, and the reversal of approximately $22.0 million of previously accrued liabilities, will be recorded in our financial statements for the period ending September 30, 2011.
28
Table of ContentsWe and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse affect on our consolidated financial results. See Note 5, “Rate Matters and Regulation,” and Note 8, “Commitments and Contingencies,” for additional information. 10. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE The following table summarizes the net periodic costs for our pension and post-retirement benefit plans prior to the effects of capitalization.
During the six months ended June 30, 2011 and 2010, we contributed $41.1 million and $16.8 million, respectively, to the Westar Energy pension trust.
29
Table of Contents11. WOLF CREEK INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. The following table summarizes the net periodic costs for KGE’s 47% share of the Wolf Creek pension and other post-retirement benefit plans prior to the effects of capitalization.
During the six months ended June 30, 2011 and 2010, we funded $7.1 million and $1.8 million, respectively, of Wolf Creek’s pension plan contribution. 12. COMMON STOCK On May 19, 2011, Westar Energy’s shareholders approved an amendment to its Restated Articles of Incorporation to increase the number of shares of common stock authorized to be issued from 150.0 million to 275.0 million. During the six months ended June 30, 2011, Westar Energy delivered approximately 3.1 million shares of common stock as partial settlement of the forward sale agreement entered into with a bank in April 2010. In connection with these settlement transactions, Westar Energy received proceeds of $66.3 million. Assuming physical share settlement of the approximately 1.2 million remaining shares of common stock under this agreement at June 30, 2011, Westar Energy would have received aggregate proceeds of approximately $25.8 million based on an average forward price of $22.42 per share. During the six months ended June 30, 2011, Westar Energy did not deliver any shares of common stock under the forward sale agreement entered into with a bank in November 2010. Assuming physical share settlement of the approximately 8.5 million shares of common stock under this agreement at June 30, 2011, Westar Energy would have received aggregate proceeds of approximately $200.4 million based on an average forward price of $23.63 per share.
30
Table of Contents13. VARIABLE INTEREST ENTITIES In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in JEC, our 50% interest in La Cygne unit 2 and railcars we use to transport coal to some of our plants are VIEs of which we are the primary beneficiary. We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of such entities. We also continuously assess whether we are the primary beneficiary of the VIEs with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary. 8% Interest in Jeffrey Energy Center Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits. 50% Interest in La Cygne Unit 2 Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.
31
Table of ContentsRailcars Under two separate agreements that expire in May 2013 and November 2014, we lease railcars from trusts to transport coal to some of our power plants. The trusts were financed with equity contributions from owner participants and debt issued by the trusts. The trusts were created specifically to purchase the railcars and lease them to us, and do not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trusts. In determining the primary beneficiary of the trusts, we concluded that the activities of the trusts that most significantly impact their economic performance and that we have the power to direct include the operation, maintenance and repair of the railcars and our ability to exercise a purchase option at the end of the agreements at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trusts that could potentially be significant if the fair value of the railcars at the end of the agreements is greater than the fixed amounts. Our agreements with these trusts also include renewal options during which time we would pay a fixed amount of rent. We have the potential to receive benefits from the trusts during the renewal periods if the fixed amount of rent is less than the amount we would be required to pay under a new agreement. Financial Statement Impact We have recorded the following assets and liabilities on our consolidated balance sheets as a result of consolidating the VIEs described above.
All of the liabilities noted in the table above relate to the VIEs’ ownership of the reported property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs’ debt holders have no recourse to our general credit. We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.
32
Table of Contents14. LEASES Capital Leases We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements. The lease term for vehicles is from two to seven years depending on the type of vehicle. Computer equipment has a lease term of four to five years. On April 28, 2011, FERC issued an order approving a power supply agreement with the City of McPherson, Kansas. The agreement extends through May 2039. The terms of the agreement meet the criteria such that it is classified as a capital lease. Consequently, we recorded a $40.0 million capital lease. Assets recorded under capital leases are listed below.
Capital lease payments are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||