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Empire District Electric Company 10-Q 2007 Documents found in this filing:UNITED STATES WASHINGTON, D.C. 20549
FORM 10-Q
Commission file number: 1-3368 THE EMPIRE DISTRICT ELECTRIC COMPANY (Exact name of registrant as specified in its charter)
Registrant’s telephone number: (417) 625-5100 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 o Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x As of May 1, 2007, 30,362,953 shares of common stock were outstanding.
THE EMPIRE DISTRICT ELECTRIC COMPANY INDEX
2 Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate,” “believe,” “expect,” “project,” “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include: · the amount, terms and timing of rate relief we seek and related matters; · the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs; · weather, business and economic conditions and other factors which may impact sales volumes and customer growth; · operation of our electric generation facilities and electric and gas transmission and distribution systems; · the costs and other impacts resulting from natural disasters, such as tornados and ice storms; · the periodic revision of our construction and capital expenditure plans and cost estimates; · legislation; · regulation, including environmental regulation (such as NOx regulation); · competition, including the implementation of the energy imbalance market; · electric utility restructuring, including ongoing federal activities and potential state activities; · the impact of electric deregulation on off-system sales; · changes in accounting requirements; · other circumstances affecting anticipated rates, revenues and costs; · the timing of, accretion estimates, and integration costs relating to, completed and contemplated acquisitions and the performance of acquired businesses; · matters such as the effect of changes in credit ratings on the availability and our cost of funds; · interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements; · the success of efforts to invest in and develop new opportunities; and · costs and effects of legal and administrative proceedings, settlements, investigations and claims. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made. We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements. 3 Item 1. Consolidated Financial Statements THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
See accompanying Notes to Consolidated Financial Statements.
4 THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)(Continued)
See accompanying Notes to Consolidated Financial Statements. 5 THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
See accompanying Notes to Consolidated Financial Statements 6 THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(continued) See accompanying Notes to Consolidated Financial Statements
7 THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED(Continued)
See accompanying Notes to Consolidated Financial Statements. 8 THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
See accompanying Notes to Consolidated Financial Statements. 9 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 1 - Summary of Significant Accounting Policies We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. It provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment includes investments in certain non-regulated businesses including fiber optics and Internet access. These businesses are held by our wholly-owned subsidiary, EDE Holdings, Inc (EDE Holdings). The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006. The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2006. The Missouri Public Service Commission (MPSC) issued an order pertaining to our electric segment on December 21, 2006 granting us an annual increase of $29.4 million (including regulatory amortization), or 9.96%, with an effective date of January 1, 2007 and eliminating the Interim Energy Charge (IEC). The accounting treatment in this order includes regulatory amortization which provides us additional cash flow through rates to begin recovery of costs associated with our current generation expansion. This regulatory amortization was $2.6 million in the first quarter of 2007 and has been recorded as depreciation expense. Additionally, the MPSC adopted an agreement of the parties to continue the FAS 87 tracker for pension costs implemented in our March 2005 rate case. This order also establishes a similar mechanism for FAS 106 other postretirement benefit expenses. Please see Note 9 for further discussion of pension and other postretirement benefit regulatory treatment. On February 1, 2007, the Southwest Power Pool (SPP) regional transmission organization (RTO) launched its Energy Imbalance Services (EIS) market. The EIS market is monitored by our Wholesale Energy group. Sales and purchase transactions are netted on an hourly basis to determine if we are a net seller or a net purchaser. Net sales for the week are recorded as off-system sales while net purchases are recorded as purchased power. A major ice storm struck virtually all areas of our electric service territory January 12-14, 2007 causing substantial damage. Approximately 85,000 (52%) of our electric customers were without power at the height of the storm. Costs associated with the restoration effort due to the ice storm were approximately $29.0 million, of which $18.0 million was capitalized as additions to our utility plant. Approximately $4.4 million was recorded as maintenance expense in the first quarter of 2007 and approximately $6.5 million was deferred as a regulatory asset as we believe it is probable that these costs will be recoverable in future electric rate cases. 10 Note 2 - Recently Issued Accounting Standards On September 15, 2006, the FASB issued FASB No. 157, “Fair Value Measurements” (FAS 157), which provides guidance for using fair value to measure assets and liabilities. FAS 157 also responds to investors’ requests for more information about (1) the extent to which companies measure assets and liabilities at fair value, (2) the information used to measure fair value and (3) the effect that fair-value measurements have on earnings. FAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any new circumstances. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We have not yet completed our review regarding the impact of the adoption of this standard. On February 15, 2007, the FASB issued FASB No. 159, “The Fair-Value Option for Financial Assets and Financial Liabilities – including an amendment of FAS 115” (FAS 159). Under FAS 159, a company may elect to measure eligible financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings at each subsequent reporting date. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We have not yet completed our review regarding the impact of the adoption of this standard. See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2006 for further information regarding recently issued accounting standards. Note 3 – FASB Interpretation No. 48 (FIN 48) – Accounting for Uncertainty in Income Taxes On July 13, 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2003. We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we recognized approximately $54,000 of additional liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. At January 1, 2007 and March 31, 2007, our balance sheet included approximately $219,000 and $237,000, respectively, of unrecognized tax benefits. At March 31, 2007, this balance includes $230,000 of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. We do not expect any material changes to unrecognized tax benefits within the next twelve months. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. We recognize interest accrued and penalties related to unrecognized tax benefits in other expenses. Note 4 – Regulatory Matters The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet. 11 Regulatory Assets and Liabilities
(1) Primarily reflects regulatory assets resulting from the adoption of FAS 158 and regulatory accounting for EDG acquisition costs. Pension and Other Postretirement Benefits: As discussed in Note 1, effective January 1, 2007, the MPSC granted regulatory treatment for our other postretirement benefit costs and corresponding increases in regulatory liabilities for our electric operations similar to the treatment already in place for our pension costs. We now recognize a regulatory asset or liability, respectively, for costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension costs and the Missouri EDE portion of other postretirement benefit costs. Since January 1, 2007, approximately $0.7 million in additional expenses and corresponding increases in regulatory liabilities have been recognized. Note 5 – Acquisition of Missouri Natural Gas Distribution Operations On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. This acquisition was completed by our wholly-owned subsidiary, The Empire District Gas Company (EDG), on June 1, 2006. We expect this acquisition to help diversify our weather risk, balancing our current summer air conditioning peak with a natural gas winter heating peak. This transaction was subject to the approval of the MPSC, which was obtained, effective May 1, 2006. The total purchase price, including working capital and net plant adjustments but excluding acquisition costs, was $102.5 million. We recorded $39.4 million of goodwill as a result of the acquisition. All of this goodwill is expected to be tax deductible. The components of the purchase price allocation for the Missouri Gas acquisition are shown below. Assets and liabilities were valued at fair value. In the case of property, plant and equipment, fair value was calculated in a manner consistent with the amount recoverable for regulatory treatment. 12
The following presents certain consolidated proforma financial information for the three months ended March 31, 2006 and the twelve months ended March 31, 2007 and 2006 as if our acquisition of Missouri Gas had been completed as of April 1, 2005. These estimates are based on historical results of the Missouri Gas operations, provided to us by Aquila, Inc., and are unaudited.
Note 6 – Risk Management and Derivative Financial Instruments Electric We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel, on the volatile spot market and to manage certain interest rate exposure. A $10.7 million net of tax, unrealized gain representing the fair market value of derivative contracts treated as cash flow hedges is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of March 31, 2007. The tax effect of $6.6 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning April 1, 2007 and ending on September 30, 2011. At the end of each determination period, or if cash flow hedge treatment is discontinued, any gain or loss for that period related to the instrument will be reclassified to fuel expense. We record unrealized gains/(losses) on the ineffective portion of our gas hedging activities in “Fuel” under the Operating Revenue Deductions section of our statement of operations since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. The following table sets forth “mark-to-market” pre-tax gains/(losses) from the ineffective portion of our hedging activities for electric generation and the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts included in “Fuel” for each of the periods ended March 31: 13
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases. We have instituted a process to determine if any future executed contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly. As of April 13, 2007, 87% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2007 is hedged, either through physical or financial contracts, at an average price of $6.257 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for the next six years are hedged at the following average prices per Dth:
Gas We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. As of April 20, 2007, we have none of our expected usage hedged for the upcoming winter heating season (November 2007 through March 2008) with physical forward contracts or financial derivative contracts. We target to have 95% of our storage capacity full by November 1 of the upcoming winter heating season. As of April 21, 2007, we have 0.5 million Dths in storage on the three pipelines that serve our customers. This represents 24% of our storage capacity leaving 1.5 million Dths to be injected into storage by November 1, 2007 to meet our 95% target. Our long-term hedge positions for gas purchased for resale are still in the development process. A purchased gas adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet. Note 7 – Financing On March 26, 2007, EDE issued $80 million principal amount of First Mortgage Bonds, 5.875% Series due 2037. The net proceeds of $79.1 million, less $0.2 million of legal and other financing fees, were added to our general funds and used to pay down short-term indebtedness incurred as a result of our on-going construction program. On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime 14 commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $61.5 million as of April 1, 2007. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2007, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at March 31, 2007, however, $39.8 million of the availability thereunder was used at such date to back up our outstanding commercial paper. Note 8 – Commitments and Contingencies We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5). In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse affect upon our financial condition, or results of operations or cash flows. Coal, Natural Gas and Transportation Contracts We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. The firm physical gas and transportation commitments total $50.9 million for April 1, 2007 through March 31, 2008, $60.2 million for April 1, 2008 through March 31, 2010, $45.5 million for April 1, 2010 through March 31, 2012 and $74.4 million for April 1, 2012 and beyond. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price. We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements are $25.5 million for April 1, 2007 through March 31, 2008, $30.4 million for April 1, 2008 through March 31, 2010 and $4.1 million for April 1, 2010 through March 31, 2012. 15 Purchased Power We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules. We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $51.3 million through May 31, 2010. We also have a long term agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. We have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. Commitments under this contract total approximately $53.0 million through December 31, 2015. New Construction On March 14, 2006, we entered into contracts to purchase an undivided interest in 50 megawatts of the Plum Point Energy Station’s new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. The estimated cost is approximately $103 million in direct costs, including AFUDC. In addition, we entered into an agreement with KCP&L on June 13, 2006 to purchase an undivided ownership interest in the proposed coal-fired Iatan 2. We will own 12%, or approximately 100 megawatts, of the proposed 850-megawatt unit. Our share of the Iatan 2 costs will range from approximately $183.6 million to $200.5 million, excluding AFUDC. Leases On December 10, 2004, we entered into a 20-year contract with Elk River Windfarm, LLC to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or 10% of our annual needs under the contract, which was declared commercial on December 15, 2005. We do not own any portion of the windfarm. Payments for wind energy from the Elk River Windfarm are contingent upon output of the facility. Payments can run from zero to a maximum of $15.2 million based on a 20 year average cost and the estimated output of 550,000 megawatt hours. These costs are recorded as purchased power expenses, and are not included in the operating lease obligations shown below. We also currently have short-term operating leases for two unit trains to meet coal delivery demands and garage and office facilities for our electric segment and five service center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment. 16 Our obligations over the next five years are as follows:
The accumulated amount of amortization for our capital leases was $0.2 million at March 31, 2007. Environmental Matters We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and wastes, including their identification, transportation, disposal, record-keeping and reporting, including asbestos, as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations. Electric Segment Air. The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan Power Plants and Units 3 and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx). The Asbury Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired boiler on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an affected unit for SO2 and NOx on January 1, 2000. Units 3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003. The new Riverton Unit 12 became an affected unit in January 2007. 17 SO2 Emissions. Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been awarded a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances may be traded between plants or utilities or “banked” for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency (EPA) withholds annually a percentage of the emission allowances awarded to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these withheld allowances. In 2006, our Asbury, Riverton and Iatan plants burned a blend of low sulfur Western coal (Powder River Basin) and higher sulfur blend coal and petroleum coke, or burned 100% low sulfur Western coal. In addition, tire-derived fuel (TDF) was used as a supplemental fuel at the Asbury Plant. The Riverton Plant can also burn natural gas as its primary fuel. The State Line Plant, the Energy Center Units 3 and 4 and the new Riverton Unit 12 are gas-fired facilities and do not receive SO2 allowances. In the near term, annual allowance requirements for the State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. In 2006, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances awarded to us by the EPA, therefore, as of December 31, 2006, we had 31,000 banked SO2 allowances as compared to 41,000 at December 31, 2005. Based on current SO2 allowance usage projections, we will need to construct a scrubber at Asbury or purchase additional SO2 allowances sometime before 2011. On July 14, 2004, we filed an application with the MPSC seeking an order authorizing us to implement a plan for the management, sale, exchange, transfer or other disposition of our SO2 emission allowances issued by the EPA. On March 1, 2005, the MPSC approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances. SO2 emissions will be further regulated as described in the Clean Air Interstate Rule section below. NOx Emissions. The Asbury, Iatan, State Line, Energy Center and Riverton Plants are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated. The Asbury Plant received permission from the Missouri Department of Natural Resources (MDNR) to burn TDF at a maximum rate of 2% of total fuel input. During 2006, approximately 5,794 tons of TDF were burned. This is equivalent to 579,400 discarded passenger car tires. Under the MDNR’s Missouri NOx Rule, our Iatan, Asbury, State Line and Energy Center facilities, like other facilities in Western Missouri, are generally subject to a maximum NOx emission rate of 0.35 lbs/mmBtu. However, facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are only subject to a higher NOx emission limit of 0.68 lbs/mmBtu. All of our plants currently meet the required emission limits and additional NOx controls are not required. NOx is further regulated as described in the Clean Air Interstate Rule below. 18 Clean Air Interstate Rule (CAIR) The EPA issued its final CAIR on March 10, 2005. CAIR governs NOx and SO2 emissions from fossil fueled units greater than 25 megawatts and will affect 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Plants are located and Arkansas where the future Plum Point Energy Station will be located. The CAIR is not directed to specific generation units, but instead, require the states (including Missouri and Arkansas) to develop State Implementation Plans (SIPs) to comply with specific NOx and SO2 state-wide annual budgets. Until these plans are finalized, we cannot determine the allowed emissions of NOx and SO2 for the Asbury, Energy Center, State Line and Iatan Plants in Missouri or the Plum Point Energy Station in Arkansas. In order to help meet anticipated CAIR requirements and to meet air permit requirements for Iatan Unit 2, we are installing pollution control equipment on Iatan Unit 1 which will be completed around the end of 2008. This equipment includes a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a baghouse, with our share of the capital cost estimated at $45 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006. Approximately $15.9 million in 2007 and $24.6 million in 2008 are included in our current capital expenditures budget. These projects were included as part of our Experimental Regulatory Plan approved by the MPSC. Also to help meet anticipated CAIR requirements, we are constructing an SCR at Asbury. We expect the SCR to be in service around January of 2008. We have awarded a contract and the SCR is under construction and will be tied into the existing unit during our scheduled 2007 fall outage. Our current cost estimate for the SCR at Asbury is $30 million, which is also included in our current capital expenditures budget. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC. We also expect that additional pollution control equipment to comply with CAIR may become economically justified at the Asbury Plant sometime prior to 2015 and may include a FGD and a baghouse at an estimated capital cost of $100 million. At this time, we do not anticipate the installation of additional pollution control equipment at the Riverton Plant. Clean Air Mercury Rule (CAMR) On March 15, 2005, the EPA issued the CAMR regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The new mercury emission limits will go into effect January 1, 2010. The CAMR is not directed to specific generation units, but instead, requires the states (including Missouri, Kansas and Arkansas) to develop State Implementation Plans (SIP) to comply with a specific mercury state-wide annual budgets. Until these state plans are finalized, we cannot determine the allowed emissions for mercury for the Asbury, Energy Center, State Line and Iatan Plants in Missouri, the Plum Point Energy Station in Arkansas or the Riverton Plant in Kansas. The proposed SIPs for all states include allowance trading programs for mercury that could allow compliance without additional capital expenditures. Based on initial testing and anticipated SIPs, we believe we will be granted enough mercury allowances on January 1, 2010 in aggregate to meet our anticipated mercury emissions. We are adding mercury analyzers at Asbury and Riverton during 2007 to get more specific data on our mercury emissions and to meet the compliance date of January 1, 2009 for mercury analyzers and the mercury emission compliance date of January 1, 2010. Water. We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The 19 Asbury, Iatan, Riverton, Energy Center and State Line plants are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The renewal for the State Line permit is under draft review with public notice expected in the first half of 2007. The Energy Center permit was renewed in September 2005 and the Asbury Plant permit was renewed in December 2005. The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act Section 316(b) Phase II. The regulations became final on February 16, 2004 and require the submission of a Comprehensive Demonstration Study with the permit renewal in 2008. A Proposal for Information Collection (PIC) has been approved by the Kansas Department of Health and Environment. Aquatic sampling commenced in April 2006 in accordance with the PIC and was completed in March 2007. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded key sections of the EPA’s February 16, 2004 regulations. At this time, the schedule for reconsideration and revisions is not known. We will be engaged with the EPA in its reconsideration and revision process. Data collection will continue under the PIC and will be expanded as needed to limit increased costs, if any, due to the EPA’s reconsiderations. At this time, we do not expect costs associated with compliance to be material. Other. Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site’s total emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Plants. We submitted the required renewal applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan is required by the renewed permit for Asbury. We estimate that the capital costs associated with the CAM plan will not exceed $2 million. A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts and, as a result, our share decreased from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and baghouse are completed, currently estimated to be late in the fourth quarter of 2008. Gas Segment The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri (the MDNR Registry). Site #2 has received a letter of no further action from the MDNR. We are reviewing various actions that may be undertaken to reduce environmental and health risks associated with the MDNR Registry site. 20 Note 9 – Pension and Other Postretirement Benefits The components of our net periodic cost of pension (expensed and capitalized) and other postretirement benefits (in thousands) are summarized below:
(1) Amortized from our regulatory asset recorded upon adoption of FAS 158. (2) Does not include the effect of regulatory accounting expenses, discussed in Note 4. Based on the performance of our pension plan assets through January 1, 2006 and 2007, we were not required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2006 or 2007. We expect to make other postretirement benefit contributions of $4.0 million in 2007, of which $1.0 million has been made as of March 31, 2007. Note 10 – Stock-Based Awards and Programs We recognized the following amounts (in thousands) in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended March 31:
The first quarter 2007 activity for our various stock plans is summarized below: Performance-Based Restricted Stock Awards The fair value of the estimated shares to be awarded under each grant of restricted stock was estimated on the date of grant using a lattice-based option valuation model with the assumptions noted in the following table: 21
Non-vested restricted stock awards (based on target number) as of March 31, 2007 and 2006 and changes during the three months ended March 31, 2007 and 2006 were as follows:
At March 31, 2007, there was $0.5 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period. Stock Options A summary of option activity under the plan during the three months ended March 31, 2007 and 2006 is presented below:
(1) 2007 includes 4,200 shares at weighted average price of $21.79, which are vested and exercisable. All others are non-vested. The aggregate intrinsic value at March 31, 2007 was $0.2 million. The aggregate intrinsic value at March 31, 2006 was less than $0.1 million. The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. 22 The range of exercise prices for the options outstanding at March 31, 2007 was $21.79 to $23.81. The weighted-average remaining contractual life of outstanding options at March 31, 2007 and 2006 was 8.3 years and 8.8 years, respectively. As of March 31, 2007, there was $0.5 million of total unrecognized compensation expense related to the non-vested options granted under the plan. That cost will be recognized over a period of 1 to 3 years.
Note 11 – Accounts Receivable - Other The following table sets forth the major components comprising “Accounts receivable – other” on our consolidated balance sheet (in thousands):
(1) The $1.8 million accounts receivable for energy trading margin deposit represents the balance in our brokerage account as of March 31, 2007. NYMEX futures contracts are used in our hedging program of natural gas which require posting of margin. (2) The $1.5 million in accounts receivable for true-up on maintenance contracts represents quarterly estimated credits from Siemens Westinghouse related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit (SLCC). Forty percent of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of March 31, 2007. Note 12 - Regulated - Other Operating Expense The following table sets forth the major components comprising “Regulated – other” under “Operating Revenue Deductions” on our consolidated statements of operations (in thousands) for all periods presented ended March 31: 23
(1) Includes effects of regulatory treatment for pension and other postretirement benefits but does not include capitalized portion or amount deferred to a regulatory asset. Note 13 – Segment Information We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. EDG is our wholly owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. The other segment consists of our businesses which are unregulated and include a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business and a 100% interest in Fast Freedom, Inc., an Internet service provider. We sold our controlling 52% interest in Mid-America Precision Products (MAPP) on August 31, 2006. MAPP is a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. We also sold our interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software. For financial reporting purposes, both of these businesses have been classified as a discontinued operation and are not included in our segment information. The tables below present information about the revenues, operating income, income from continuing operations, capital expenditures and total assets of our business segments.
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