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Empire District Electric Company 10-Q 2008
UNITED
STATES WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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 August 1, 2008, 33,888,354 shares of common stock were outstanding.
THE EMPIRE DISTRICT ELECTRIC COMPANY
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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, SO2 and CO2 regulation); · competition, including 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; · costs and effects of legal and administrative proceedings, settlements, investigations and claims; and · our exposure to the credit risk of our hedging counterparties.
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.
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THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
See accompanying Notes to Consolidated Financial Statements.
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See accompanying Notes to Consolidated Financial Statements.
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See accompanying Notes to Consolidated Financial Statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
See accompanying Notes to Consolidated Financial Statements
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THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Continued)
See accompanying Notes to Consolidated Financial Statements
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See accompanying Notes to Consolidated Financial Statements.
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THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
See accompanying Notes to Consolidated Financial Statements.
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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 primarily consists of a 100% interest in Empire District Industries Inc., a subsidiary for our fiber optics business. 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, 2007.
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, 2007. Certain reclassifications have been made to prior year information to conform to the current year presentation.
Note 2 - Recently Issued Accounting Standards
On September 15, 2006, Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” (FAS 157) was issued. We adopted this statement on January 1, 2008. See Note 13 for the discussion of this adoption and the effect of FASB Staff Position (FSP) 157-2 which amended FAS 157 to delay the effective date for all non-financial assets and liabilities.
On February 15, 2007, the Financial Accounting Standards Board (FASB) issued SFAS 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. FAS 159 had no effect on our financial statements.
On April 30, 2007, the FASB issued FASB Staff Position No. 39-1 (FIN 39), an “Amendment of FASB Interpretation No. 39”. FIN 39 is effective for fiscal years ending after November 15, 2007. It amends paragraph 3 of Interpretation 39 to replace the terms “conditional contracts and exchange contracts” with the term “derivative instruments as defined in FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities”. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that paragraph. We currently do not apply this offsetting alternative.
On December 1, 2007, the FASB issued SFAS 141(R) “Business Combinations” (FAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (FAS 160). FAS 141(R) and FAS 160 are effective for business combinations entered into in fiscal years beginning on or after December 15, 2008. FAS 141(R) changes the definitions of a business and a business combination, and will result in more transactions recorded as business combinations. Certain acquired contingencies will be recorded
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initially at fair value on the acquisition date, transactions and restructuring costs generally will be expensed as incurred and in partial acquisitions, companies generally will record 100 percent of the assets and liabilities at fair value, including goodwill.
In April 2008, the FASB issued SFAS 161 “Disclosure About Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133” (FAS 161). FAS 161 enhances the current disclosure framework in FAS 133, “Accounting for Derivative Instruments and Hedging Activities.” FAS 161 is effective for periods beginning after November 15, 2008. We do not expect the adoption of FAS 161 to have a material effect on our financial statement disclosures.
See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2007 for further information regarding recently issued accounting standards.
Note 3– Regulatory Matters
The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet.
Regulatory Assets and Liabilities
(1) Primarily reflects regulatory assets resulting from the adoption of FAS 158 and regulatory accounting for EDG acquisition costs. (2) Includes the effect of 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, 2008, approximately $2.3 million in additional regulatory liabilities and corresponding expense increases have been recognized.
Note 4– Risk Management and Derivative Financial Instruments
We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business and for sale in our natural gas business, on the volatile spot market and to manage certain interest rate exposure.
As of June 30, 2008 and December 31, 2007, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments:
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Asset Derivatives
(1) Statement of Financial Accounting Standards (SFAS) No. 133 “Accounting for Derivative Instruments and Hedging Activities” (FAS 133).
Liability Derivatives
Electric
A $30.4 million net of tax, unrealized gain representing the fair market value of our electric segment derivative contracts treated as cash flow hedges is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of June 30, 2008. The tax effect of $18.7 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning July 1, 2008 and ending on September 30, 2011. As of June 30, 2008, approximately $16.9 million of unrealized gains are applicable to financial instruments which will settle within the next twelve months.
The following table sets forth the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts for the electric segment for each of the periods ended June 30:
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 the electric segment for each of the periods ended June 30:
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The following table sets forth “mark-to-market” pre-tax gains/(losses) from derivatives not designated as hedging instruments under FAS 133 for the electric segment for each of the periods ended June 30:
(1) All of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. If conditions change, such as a planned unit outage, we may need to re-designate and/or unwind some of our previous derivatives designated under FAS 133. In this instance, these derivatives would be classified into the category above.
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 July 18, 2008, 94% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2008 is hedged, either through physical or financial contracts, at an average price of $6.895 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 five years are hedged at the following average prices per Dth:
On February 15, 2008, we unwound 992,000 Dths of physical gas contracts originally scheduled for delivery in July and August of 2010 and 2011. This transaction resulted in a gain of approximately $1.3 million after tax which was recorded in the Statement of Operations in the first quarter of 2008. We believe it is probable that we will take physical delivery under the remaining physical gas forward contracts.
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. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of July 17, 2008, we had 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36% of our storage capacity. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of second year and up to 20% of third year
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expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. 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.
The following table sets forth “mark-to-market” pre-tax gains / (losses) from financial hedging instruments for the gas segment for each of the periods ended June 30. These gains and losses are recorded to a regulatory asset or liability account due to our commission approved natural gas cost recovery mechanism discussed above.
Note 5–Financing
On May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.3 million of legal and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.
On March 11, 2008, we amended the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) in order to provide us with additional flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million. The amendment followed the successful completion of a solicitation of consents from the holders of our First Mortgage Bonds outstanding under the EDE Mortgage. We received consents from holders of 94.46% in aggregate principal amount of the outstanding bonds and paid fees of approximately $1.6 million to the consenting bondholders.
On December 12, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering for $23.00 per share. The sale resulted in net proceeds of approximately $65.7 million ($69.0 million less issuance costs of $3.3 million). The proceeds were added to our general funds and used to pay down short-term indebtedness incurred, in part, 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 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 $27.5 million as of August 1, 2008. 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 June 30, 2008, 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
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operations. There were no outstanding borrowings under this agreement at June 30, 2008, however, $12.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.
Note 6 – 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 $46.9 million for July 1, 2008 through June 30, 2009, $45.7 million for July 1, 2009 through June 30, 2011, $44.1 million for July 1, 2011 through June 30, 2013 and $61.4 million for July 1, 2013 and beyond. In the event that this gas cannot be used at our plants, the gas would remain in storage or 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. Due to the extended Asbury maintenance outage from December 9, 2007 through February 10, 2008, we issued force majeure notices to our Western coal suppliers and to the railroads suspending Western coal shipments during the outage. This relieved us of our contractual obligations to receive shipments of coal to the extent caused by the Asbury outage. The minimum requirements are $26.0 million for July 1, 2008 through June 30, 2009, and $21.0 million for July 1, 2009 through June 30, 2011.
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 $31.0 million through May 31, 2010.
We also have a long term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for 2010. 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 $48.0 million through June 30, 2015.
We have entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm to be located in Cloud County, Kansas and a 20-year contract with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc. (formerly known as PPM Energy), to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements
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are considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations discussed below.
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 is being built near Osceola, Arkansas. The estimated cost is approximately $86.5 million, excluding AFUDC.
On June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Construction began in the spring of 2006 with completion scheduled for 2010. On May 7, 2008, KCP&L announced an update of their estimated construction figures for the construction of the Iatan 2 plant and for the environmental upgrades at the Iatan 1 plant. Our share of the Iatan 2 construction costs will increase from a range of approximately $183.6 million to $200.5 million to a range of approximately $218 million to $230 million. All of these estimated construction expenditures exclude AFUDC. The updated estimate of our share of the cost for environmental upgrades at the Iatan 1 plant is a range of approximately $56 million to $60 million, representing an increase of 22%-30% compared to the previous estimate of approximately $46 million. The in-service date for the Iatan No. 1 project is expected to be February 2009.
A new combustion turbine previously scheduled to be installed by the summer of 2011 will be delayed for at least one year as our generation regulation needs for our purchased power agreements are being met through a combination of our existing units and the SPP energy imbalance market.
Leases
On June 25, 2007, we entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. The agreement provides for a 20-year term commencing with the commercial operation date, which is expected to be about January 1, 2009. We will begin taking delivery of the energy at that time. Pursuant to the terms of the agreement, we will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Way Wind Farm to be located in Cloud County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.
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 approximately 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. Annual payments can run from zero to a maximum of approximately $16.9 million based on a 20-year average cost.
Payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, 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 six service center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment.
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Our lease obligations over the next five years are as follows (in thousands):
The gross amount of assets recorded under capital leases totaled $1.3 million at June 30, 2008. The accumulated amount of amortization for our capital leases was $0.3 million at June 30, 2008.
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, 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).
SO2 Emissions. Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been allocated 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. The annual reconciliation of allowances, which occurs on a facility wide basis, is held each March 1 for the previous calendar year. 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 allocated 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.
Our Asbury, Riverton and Iatan coal plants burn a blend of low sulfur Western coal (Powder River Basin) and higher sulfur blend coal and petroleum coke, or burn 100% low sulfur Western coal. In addition, tire-derived fuel (TDF) is used as a supplemental fuel at the Asbury Plant. The
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Riverton Plant can also burn natural gas as its primary fuel. The State Line Plant, the Energy Center Units 3 and 4 and 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 2007, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances allocated to us by the EPA. Based on our March 1, 2008 EPA reconciliation, we had approximately 24,000 banked SO2 allowances at December 31, 2007 as compared to 31,000 at December 31, 2006. We project that our 2008 emissions will again exceed the number of allowances allocated by the EPA by an amount approximately equal to the difference during 2007.
When our SO2 allowance bank is exhausted, we will need to purchase additional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant. Based on current and projected SO2 allowance prices and high-level estimated FGD scrubber construction costs ($81 million in 2010 dollars), we expect it will be more economical for us to purchase SO2 allowances than to build a scrubber at the Asbury Plant. We would expect the costs of SO2 allowances to be fully recoverable in our rates.
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. Our banked allowances are not assigned a cost value. The allowances are removed from inventory on a FIFO basis.
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 2007, approximately 2,651 tons of TDF were burned. This is equivalent to 265,100 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 during the ozone season of May 1 through September 30. However, facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are 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 at this time.
In March 2008, the EPA lowered the National Ambient Air Quality Standard (NAAQS) for ozone from 84 ppb to 75 ppb. Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. It is possible that most of southwest Missouri will be classified as non-attainment or non-classified by the EPA in 2010 or later. We anticipate that the EPA will classify the Kansas City area, where Iatan 1 is located, as non-attainment in 2010. At this time we do not foresee the need for additional pollution controls due to the ozone reduction. In addition, our units do not emit appreciable VOCs. We do not anticipate that southeast Kansas will be classified as non-attainment under the new ozone NAAQS.
Clean Air Interstate Rule (CAIR)
The EPA issued its final CAIR on March 10, 2005. CAIR governed NOx and SO2 emissions from fossil fueled units greater than 25 megawatts in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Plants are located and Arkansas where the Plum Point Energy Station is being constructed. Kansas was not included in CAIR and our Riverton Plant was not affected. The CAIR was not directed to specific generation units, but instead, required the states
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(including Missouri and Arkansas) to develop specific State Implementation Plans (SIPS) to comply with specific NOx and SO2 state-wide annual budgets.
On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR Rule and remanded it back to the EPA. It is not known at this time how the remand will affect us until CAIR has been finally adjudicated.
The EPA must decide whether it will appeal the ruling, modify CAIR to address the vacated issues, rescind CAIR or replace CAIR. Missouri and Arkansas submitted CAIR SIPS to the EPA. These SIPS were approved and remain in effect until the EPA provides guidance to the states regarding the U.S. Court of Appeals ruling. No guidance has yet been issued by the EPA or the states of Missouri and Arkansas.
CAIR would have regulated SO2 by increasing the 1990 Amendments to the Clean Air Act surrender rate of 1 allowance for 1 ton of SO2 emissions to 2:1 in 2010 and 2.86:1 in 2015.
If the CAIR rulemaking is ultimately revoked by the EPA, and, subsequently, the states rescind their SIPS, the Clean Air Visibility Rule which includes Best Available Retrofit Technology (BART) requirement re-emerges under current law. Missouri had adopted CAIR as the mechanism to comply with BART. Kansas had adopted a specific BART plan, but Riverton is not considered a BART facility in the Kansas plan.
In order to help meet previously anticipated CAIR requirements and to meet air permit requirements for Iatan Unit 2, pollution control equipment is being installed on Iatan Unit 1 with the in-service date expected to be February 2009. This equipment includes a Selective Catalytic Reduction (SCR) system, an FGD scrubber and a baghouse, with our share of the capital cost estimated to be between $56 million and $60 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006 and $12.1 million in 2007 with estimated expenditures of approximately $25.7 million in 2008 and $17.5 million in 2009. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.
Also to help meet previously anticipated CAIR requirements and the existing Missouri NOx Rule, we constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008 at a total cost of approximately $31.0 million (excluding AFUDC), of which $28.1 million was expended through December 31, 2007 with the remainder expended in 2008. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.
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 for Phase 1 were scheduled to go into effect January 1, 2010 and remain in effect until January 1, 2018. Beginning January 1, 2018, more restrictive mercury emission limits were scheduled to go into effect for Phase 2 of CAMR. These regulations were challenged in the U.S. Court of Appeals for the District of Columbia Circuit by a group of states led by New Jersey. On February 8, 2008, the Court of Appeals issued its opinion and vacated the EPA’s CAMR regulations. The EPA is required to reconsider the regulation of mercury under Section 112 of the 1990 Amendments.
The EPA has not yet issued guidance to the states regarding the vacated regulation and recommended future actions. Based on CAMR, we installed a mercury analyzer at Asbury during late 2007 and scheduled the installation of two mercury analyzers at Riverton during 2008 in order to verify our mercury emissions and to meet the compliance date of January 1, 2009 for mercury analyzers and the Phase 1 mercury emission compliance date of January 1, 2010. We will complete the installation of the mercury analyzers at Riverton in anticipation of future mercury regulations.
After being finally adjudicated, if the CAMR rulemaking is ultimately revoked by the EPA, Maximum Achievable Control Technology (MACT) re-emerges under current law. No specific MACT rulemakings have yet been adopted in Missouri or Kansas.
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CO2 Emissions
Our coal and gas plants emit carbon dioxide (CO2), a greenhouse gas. Although not currently regulated, increasing public concern and political pressure from local, regional, national and international bodies may result in the passage of new laws mandating limits on greenhouse gas emissions such as CO2. Several bills addressing climate change have been introduced in the U.S. Congress and, in April 2007, the U.S. Supreme Court issued a decision ruling the EPA improperly declined to address CO2 impacts in a rule-making related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. Various proposals in the U.S. Congress could require us to purchase offsets or allowances for some or all of our CO2 emissions, or otherwise affect us based on the amount of CO2 we generate. The impact on us of any future greenhouse gas regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance.
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 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 State Line permit was renewed in May 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 (CWA) Section 316(b) Phase II. The regulations became final on February 16, 2004 and required the submission of a Sampling Report and Comprehensive Demonstration Study with the permit renewal in 2008. A Proposal for Information Collection (PIC) was approved by the Kansas Department of Health and Environment (KDHE). Aquatic sampling commenced in April 2006 in accordance with the PIC and was completed in August 2007. Analysis of the sampling and summary reports was completed during the first quarter of 2008 and submitted to the KDHE. These reports indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. The need for a further Demonstration Study is not expected. 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. On July 9, 2007, the EPA suspended the regulation and is expected to revise and re-propose the regulation by December 2008. We will monitor the EPA revision process and comment appropriately. In addition, on April 14, 2008 certiorari was granted by the United States Supreme Court limited to the review as to whether Section 316(b) of the CWA authorized the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impacts at cooling water intake structures. The permit renewal application was prepared and submitted in June 2008. Under the initial 316(b) regulations, we did not expect costs associated with compliance to be material. We will reassess costs after the Supreme Court issues its ruling and the revised rules are complete.
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 air 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 will be 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 Iatan Unit No. 2 currently under construction. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. 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 in February of 2009.
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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. Site #2 has received a letter of no further action from the MDNR. A Change of Use request and work plan was approved by the MDNR allowing us to expand our existing service center at Site #1 in Chillicothe, Missouri. This project, which was completed in October 2007, included the removal of all excavated soil and the addition of a new concrete surface replacing the existing gravel at a cost of approximately $0.1 million. We estimate further remediation costs at these two sites to be no more than approximately $0.2 million, based on our best estimate at this time. This estimated liability is recorded under noncurrent liabilities and deferred credits. In our agreement with the MPSC approving the acquisition of Missouri Gas, it was agreed that we could reflect a liability and offsetting regulatory asset not to exceed $260,000 for the acquired sites. The MPSC agreed that up to $260,000 of costs related to the clean up of these MGP sites would be allowed for future rate recovery. Accordingly, we concluded that rate recovery was probable and at the acquisition date, a regulatory asset of $260,000 was recorded as part of the purchase price allocation based on our agreement with the MPSC, and in accordance with Statement of Financial Accounting Standards No. 71 – “Accounting for the Effects of Certain Types of Regulation” (FAS 71).
Note 7 – Retirement Benefits
Net periodic benefit pension cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components (in thousands):
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