Empire District Electric Company 10-K 2007
Documents found in this filing:
WASHINGTON, D.C. 20549
For the fiscal year ended December 31, 2006 or
For the transition period from to .
Commission file number: 1-3368
THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Registrants telephone number: (417) 625-5100
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
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 disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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
The aggregate market value of the registrants voting common stock held by nonaffiliates of the registrant, based on the closing price on the New York Stock Exchange on June 30, 2006, was approximately $618,350,733.
As of February 16, 2007, 30,296,442 shares of common stock were outstanding.
The following documents have been incorporated by reference into the parts of the Form 10-K as indicated:
This Amendment No. 1 to the Annual Report on Form 10-K/A for the fiscal year ended December 31, 2006 is being filed solely for the purpose of correcting typographical errors in the financial statement title on the Consolidated Statements of Common Shareholders Equity. The Annual Report was filed with the Securities and Exchange Commission on March 2, 2007 by the Registrant.
For the convenience of the reader, this Form 10-K/A sets forth the originally filed Form 10-K in its entirety. However, the only change to the original Form 10-K being made by this Form 10-K/A is the change described above. This Form 10-K/A does not reflect events occurring after the filing of the original Form 10-K or modify or update any other disclosures. Information not affected by the amendment is unchanged and reflects the disclosures made at the time of the filing of the original Form 10-K.
Certain matters discussed in this annual 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;
· regulation, including environmental regulation (such as NOx regulation);
· competition, including the launch 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.
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. In 2006, 93.0% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 6.1% from our gas segment, and 0.9% from our other segment.
The territory served by our electric operations embraces an area of about 10,000 square miles with a population of over 450,000. The service territory is located principally in southwestern Missouri and also includes smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal activities of these areas include light industry, agriculture and tourism. Of our total 2006 retail electric revenues, approximately 87.6% came from Missouri customers, 6.1% from Kansas customers, 3.0% from Oklahoma customers and 3.3% from Arkansas customers.
We supply electric service at retail to 121 incorporated communities and to various unincorporated areas and at wholesale to four municipally owned distribution systems. The largest urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 157,000. We operate under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 67% of our electric operating revenues in 2006 were derived from incorporated communities with franchises having at least ten years remaining and approximately 2% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.
Our electric operating revenues in 2006 were derived as follows: residential 41.7%, commercial 30.1%, industrial 16.9%, wholesale on-system 4.6%, wholesale off-system 3.2% and other 3.5%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2006 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 2% of electric revenues in 2006.
Our gas operations, which we purchased from Aquila, Inc. on June 1, 2006, serve customers in northwest, north central and west central Missouri. The principal utility properties consist of approximately 87 miles of transmission mains and approximately 1,105 miles of distribution mains. We provide natural gas distribution to 44 communities in northwest, north central and west central Missouri and 174 transportation customers. Our gas operating revenues in 2006 were derived as follows: residential 67.6%, commercial 30.2%, industrial 1.5% and other 0.7%. No single retail customer accounted for more than 4% of gas revenues in 2006. The largest urban area we serve is the City of Sedalia with a population of over 20,000. We operate under franchises having original terms of twenty years in virtually all of the incorporated communities. Thirty-one of the franchises have 10 years or more remaining on their term. Although our franchises contain no renewal provisions, since our acquisition, we have obtained renewals of all our expiring gas franchises prior to the expiration dates.
Our other segment businesses, which we operate through our wholly-owned subsidiary EDE Holdings, Inc., include leasing of fiber optics cable and equipment (which we are also using in our own operations) and Internet access services. In August 2006, we sold our controlling 52% interest in Mid-America Precision Products (MAPP) to other current owners. MAPP specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software. See Item 2, Properties Other Segment Businesses for further information about our other segment businesses.
On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The base purchase price was $85 million in cash, plus working capital and subject to net plant adjustments. This transaction was subject to the approval of the Missouri Public Service Commission (MPSC). On March 1, 2006, we, Aquila, Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with the MPSC, requesting it approve the proposed transaction. On April 18, 2006, the MPSC issued an Order Approving Unanimous Stipulation and Agreement and Granting a Certificate of Public Convenience and Necessity, effective May 1, 2006. We announced the completion of this acquisition on June 1, 2006. The total purchase price paid to Aquila, Inc., including working capital and net plant adjustments of $17.1 million, was $102.1 million, not including acquisition costs. As of December 31, 2006, the $102.1 million has been increased to $102.5 million for additional true-up items. The acquisition was initially financed by $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG, and with short-term debt issued by EDE. This short-term debt was repaid with the proceeds of the sale of our common stock on June 21, 2006.
At December 31, 2006, our generating plants consisted of:
* based on summer rating conditions as utilized by Southwest Power Pool.
See Item 2, Properties Electric Segment Facilities for further information about these plants.
We, and most other electric utilities with interstate transmission facilities, have placed our facilities under the Federal Energy Regulatory Commission (FERC) regulated open access tariffs that provide all wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same rates) that the utilities provide themselves. We are a member of the Southwest Power Pool Regional Transmission Organization (SPP RTO). On February 1, 2007, the SPP RTO launched its energy imbalance services market (EIS). With the implementation of the SPP RTO EIS market, we anticipate that our participation will provide long-term benefits to our customers and other stakeholders. However, we are unable to quantify the potential impact of such EIS participation on our future financial position, results of operation or cash flows at this time.
This SPP RTO EIS market is expected to provide economical real time energy for participating members within the SPP regional footprint. Imbalance energy prices will be based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO will perform a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.
We will continue to actively engage with the SPP RTO, other members of the SPP and staffs of our state commissions to evaluate the impact/value of EIS market participation. See Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Competition.
We currently supplement our on-system generating capacity with purchases of capacity and energy from other sources 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 rules. The SPP requires its members to maintain a minimum 12% capacity margin. We have contracted with Westar Energy for the purchase of 162 megawatts of capacity and energy through May 31, 2010 and have contracted to add 50 megawatts of purchased power beginning in 2010 from the Plum Point Energy Station discussed below. The amount of capacity purchased under such contracts supplements our on-system capacity and contributes to meeting our current expectations of future power needs.
On March 14, 2006, we entered into contracts to add 100 megawatts of power to our system. This power will come from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for 2010. Initially we will own, through an undivided interest, 50 megawatts of the projects capacity for approximately $103 million in direct costs, including allowance for funds used during construction (AFUDC). We also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. We spent $19.6 million through December 31, 2006 and anticipate spending an additional $25.8 million in 2007, $28.6 million in 2008 and $19.2 million in 2009 for construction expenses (including AFUDC) related to our 50 megawatt ownership share of Plum Point Unit 1 with additional expenditures in 2010.
On February 4, 2005, we filed an application with the MPSC seeking approval of an Experimental Regulatory Plan (Plan) concerning our possible participation in a new 800-850 MW coal-fired unit (Iatan 2) to be operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri, or other baseload generation options. Our application also sought a certificate of convenience and necessity to participate in Iatan 2, if necessary, and in connection therewith, obtain approval that is intended to provide adequate assurance to potential investors to make financial options available to us concerning our potential investment in Iatan 2. On July 18, 2005, we filed a Stipulation and Agreement (Agreement) regarding our Plan with the MPSC for its consideration and approval conditioned upon our participation in Iatan 2. The Agreement contains conditions related to our infrastructure investments, including Iatan 2, environmental investments in Iatan 1, the 155 MW V84.3A2 combustion turbine at our Riverton plant and installing Selective Catalytic Reduction (SCR) equipment at the Asbury coal-fired plant. The other parties to the Agreement include the Missouri Department of Natural Resources, the MPSC Staff, two of our industrial customers and the Office of the Public Counsel. The MPSC issued an order on August 2, 2005 approving the Agreement with an effective date of August 12, 2005.
In relation to the Plan, 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. On December 12, 2006, KCP&L announced that the total estimated construction budget for Iatan 2, originally reported to be approximately $1.34 billion, had increased to a range of approximately $1.53 billion to $1.67 billion due to increases in estimated costs for
labor, materials and equipment and also reflecting other market conditions. KCP&L, which will own 54.7% of the unit, announced their expected share of the total construction costs, originally reported to be approximately $733 million, would actually range from approximately $837 million to $914 million, due to the increase in estimated costs. Accordingly, our share of the Iatan 2 costs will increase from approximately $160.8 million to a range of approximately $183.6 million to $200.5 million. These estimated construction expenditures exclude AFUDC.
Our current capital expenditures budget, discussed below, includes $45.6 million in 2007, $85.0 million in 2008 and $64.7 million in 2009 for our share of Iatan 2 with additional expenditures in 2010. At December 31, 2006, we have recorded approximately $12.4 million in construction expenditures on this project. The Iatan 2 capital expenditures budget includes AFUDC of $1.6 million, $5.9 million and $10.3 million for 2007, 2008 and 2009, respectively. As of December 12, 2006, KCP&L stated it had approximately 50% of the total estimated cost of Iatan 2 under firm contract and had started construction activities at the site. Iatan 2 is on schedule with the completion targeted for 2010.
As a requirement for the air permit for Iatan 2, and to help meet requirements of the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR), additional emission control equipment is required for Iatan 1. According to KCP&L, Iatan 1 environmental upgrades are on schedule, with approximately 69% of the total estimated costs under firm contract as of December 31, 2006. Our share of the environmental upgrade costs at Iatan 1 is estimated at $49 million, including AFUDC, and will be expended between 2006 and May 2009. At December 31, 2006, we have spent approximately $3.9 million on this project.
Due to increased customer growth, we have purchased, and are installing at our Riverton facility, a Siemens V84.3A2 combustion turbine with an expected summer capacity of 155 megawatts to be operational in the spring of 2007 to allow us to meet the SPPs 12% minimum capacity margin requirement.
The following chart sets forth our purchase commitments and our anticipated owned capacity (in megawatts) during the indicated contract years (which run from June 1 to May 31 of the following year). The capacity ratings we use for our generating units are based on summer rating conditions under SPP guidelines. The 155 megawatts from the new Riverton combustion turbine are included under anticipated owned capacity beginning in 2007. The purchased power received from the Elk River windfarm, with which we have contracted to purchase approximately 550,000 megawatt-hours of energy per year, is not included in this chart. Because the wind power is an intermittent, non-firm resource, SPP rating criteria does not allow us to count a substantial amount of the wind power as capacity. See Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources.
* Contract years begin June 1 and run through May 31 of the following year.
** The contract years 2010 and 2011 assume 50 megwatts of purchased power capacity from Plum Point Unit 1, 50 megawatts of owned capacity from Plum Point Unit 1 and 100 megawatts of owned capacity from Iatan 2.
The charges for capacity purchases under the Westar contract referred to above during calendar year 2006 amounted to approximately $16.2 million. Minimum charges for capacity purchases under the Westar contract total approximately $64.8 million for the period June 1, 2006 through May 31, 2010.
The maximum hourly demand on our system reached a record high of 1,159 megawatts on July 19, 2006. Our previous record peak of 1,087 megawatts was established in July 2005. A new maximum hourly winter demand of 1,034 megawatts was set on January 31, 2007. Our previous winter peak of 1,031 megawatts was established on December 9, 2005.
We acquired the Missouri natural gas distribution operations of Aquila, Inc. on June 1, 2006. At December 31, 2006, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,105 miles of distribution mains.
The following table sets forth the three pipelines that serve our gas customers:
The bulk of physical supply to serve our natural gas operations comes from mid-continent production areas with about 10% of supply typically from Wyoming/Colorado production and resources.
We have agreements with many of the major suppliers and firm transportation to multiple production zones in the mid-continent region to provide for diverse supply. We continue to seek additional supplier agreements to provide for diversity and competition in meeting requirements.
The maximum daily flow on our system for 2006 was December 7, 2006 at 60,890 mcfs.
Total gross property additions (including construction work in progress) for the three years ended December 31, 2006, amounted to $235.2 million and retirements during the same period amounted to $22.2 million. Please refer to Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources for more information.
Our total capital expenditures, including AFUDC, but excluding expenditures to retire assets, were $120.2 million in 2006 and for the next three years are estimated for planning purposes (excluding costs associated with the January 2007 ice storm) to be as follows:
Construction expenditures for new generating facilities and additions to our transmission and distribution systems to meet projected increases in customer demand constitute the majority of the projected capital expenditures for the three-year period listed above. The primary costs included in new electric generating facilities are for Iatan 2, the Plum Point Energy Station and our Riverton combustion turbine. The primary costs included in additions to existing electric generating facilities include environmental upgrades at our Asbury plant and at Iatan 1.
Iatan 2 and Plum Point Unit 1 are important components of a long-term, least-cost resource plan to add approximately 200 megawatts of new coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area and the expiration of a major purchase power contract in 2010.
Estimated capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction and the availability and cost of alternative power. Actual capital expenditures may vary significantly from the estimates due to a number of factors including changes in equipment delivery schedules, changes in customer requirements, construction delays, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from independent power producers and co-generators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See Regulation below and Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Competition.
In 2006, 62.9% of our total system input, based on kilowatt-hours generated, was supplied by our steam and combustion turbine generation units, 0.4% was supplied by our hydro generation, and we purchased the remaining 36.7%, including wind energy. Coal supplied approximately 72.5% of the total
fuel requirements for our generating units in 2006 based on kilowatt-hours generated. The remainder was supplied by natural gas (27.1%) and tire-derived fuel (TDF) (0.4%), which is produced from discarded passenger car tires. The amount and percentage of electricity generated by natural gas decreased significantly in 2006 as compared to 2005 due to the energy we purchased from the Elk River Windfarm, LLC in 2006. We have a 20-year contract with Elk River Windfarm, LLC to purchase approximately 550,000 megawatt-hours of energy per year, or approximately 10% of our annual needs. The windfarm was declared commercial on December 15, 2005. This source of power allows us to displace higher-priced purchased power or system generation. We sell the renewable energy credits to third parties to further reduce our costs.
Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel and TDF being used as a supplement fuel. In 2006, Asbury burned a coal blend consisting of approximately 80.8% Western coal (Powder River Basin) and 19.2% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2006, we had sufficient coal on hand to supply anticipated requirements at Asbury for 79-83 days, as compared to 27-40 days as of December 31, 2005, depending on the actual blend ratio within this range. During the fourth quarter of 2006, we were able to increase the Asbury inventory (which declined in 2005 and 2006 as a result of railroad transportation problems) due to a combination of coal conservation, obtaining additional unit trains and improvements in the recent railroad transportation problems.
Our Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by petroleum coke, natural gas and oil. During 2006, Riverton Units 7 and 8 burned an estimated blend of approximately 81.2% Western coal (Powder River Basin) and 18.8% blend fuel (local coal and petroleum coke) on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. As of December 31, 2006, we had approximately 35,683 tons of Western coal and approximately 9,167 tons of blend fuel at Riverton. Riverton Unit 7 requires a minimum amount of blend fuel to operate, while Riverton Unit 8 can burn 100% Western coal or a mix of Western and blend fuel. Based on these assumptions, we had sufficient coal to run 36 days on both units as compared to 27 days as of December 31, 2005. Riverton receives its Western inventory from coal transported by train to the Asbury Plant which is then transported by truck to Riverton. Therefore, the lower inventory at Riverton as of December 31, 2006, is offset by the larger inventory at the Asbury Plant which will be realigned throughout the course of 2007.
We have secured, through contracts and binding proposals, 100% of our anticipated Western coal requirements for 2007, 78% for 2008, 52% for 2009 and 41% for 2010 through a combination of Peabody Coal Sales, Peabody Coal Trade, Arch Coal Sales and Rio Tinto. All of the Western coal is shipped to the Asbury Plant by rail, a distance of approximately 800 miles, under a five-year contract with the Burlington Northern and Santa Fe Railway Company (BNSF) and The Kansas City Southern Railway Company which expires on June 29, 2010. The overall delivered price of coal is expected to be slightly higher in 2007 than in 2006 due to the tightness in the market caused by recent rail transportation issues. We own one unit train set which was leased to another utility in 2006. We currently lease one aluminum unit train on a full time basis and a second set is leased on an interim basis. These trains deliver Western coal to the Asbury Plant. The Western coal is transported from Asbury to Riverton via truck. We have a long-term contract expiring December 31, 2007 with Phoenix Coal Sales, Inc. for a supply of blend coal. In 2006, the Riverton Plant primarily burned petroleum coke supplemented by a small quantity of Phoenix blend coal. Both Phoenix coal and petroleum coke are transported to Riverton and Asbury via truck.
Unit No. 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by KCP&L (70%), Aquila (18%) and us (12%). KCP&L is the operator of this plant and is responsible for arranging its fuel supply. KCP&L has secured contracts for low sulfur Western coal in quantities sufficient to meet substantially all of Iatans requirements for 2007 and 2008, approximately 50% for 2009 and approximately 47% for 2010. The coal is transported by rail under a contract expiring on December 31, 2010, with BNSF.
Our Energy Center and State Line combustion turbine facilities (not including the State Line Combined Cycle (SLCC) Unit, which is fueled 100% by natural gas) are fueled primarily by natural gas with oil also available for use as needed. During 2006, essentially all of the Energy Center generation came from natural gas. Based on kilowatt hours generated, State Line Unit 1 fuel consumption during 2006 was 86.7% natural gas with the remainder being oil. Our targeted oil inventory at the Energy Center facility permits eight days of full load operation on Units No. 1, 2, 3 and 4. As of December 31, 2006, we have oil inventories sufficient for approximately 3 days of full load operation for these units at the Energy Center and 4 days of full load operation for State Line Unit No. 1.
We have firm transportation agreements with Southern Star Central Pipeline, Inc. with original expiration dates of July 31, 2016, for the transportation of natural gas to the SLCC. This date is adjusted for periods of contract suspension by us during outages of the SLCC. This transportation agreement can also supply natural gas to State Line Unit No. 1, the Energy Center or the Riverton Plant, as elected by us on a secondary basis. In 2002, we signed a precedent agreement with Williams Natural Gas Company (now Southern Star Central), which provides additional transportation capability for 20 years. This contract provides firm transport to the sites listed above that previously were only served on a secondary basis. We expect that these transportation agreements will serve nearly all of our natural gas transportation needs for our generating plants over the next several years. Any remaining gas transportation requirements, although small, will be met by utilizing capacity release on other holder contracts, interruptible transport, or delivered to the plants by others. The majority of our physical natural gas supply requirements will be met by short-term forward contracts and spot market purchases. Forward natural gas commodity prices and volumes are hedged several years into the future in accordance with our Risk Management Policy in an attempt to lessen the volatility in our fuel expense and gain predictability.
The following table sets forth a comparison of the costs, including transportation and other miscellaneous costs, per million Btu of various types of fuels used in our electric facilities:
Our weighted cost of fuel burned per kilowatt-hour generated was 2.6502 cents in 2006, 2.891 cents in 2005 and 1.885 cents in 2004.
The bulk of physical supply to serve our natural gas operations comes from mid-continent production areas with about 10% of supply typically from Wyoming/Colorado production and resources.
We have agreements with many of the major suppliers and firm transportation to multiple production zones in the mid-continent region to provide for diverse supply. We continue to seek additional supplier agreements to provide for diversity and competition in meeting requirements.
The following table sets forth the current costs, including transportation and other miscellaneous costs, per mcf of gas used in our gas operations:
At December 31, 2006, we had 705 full-time employees, including 57 employees of EDG, who joined us in conjunction with the acquisition in June 2006. 330 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW), while 29 of the EDG employees are members of Local 814 of the IBEW and 9 are members of Local 695 of the IBEW. During 2006, we negotiated with IBEW Local 1474 to attempt to reach agreement on a new contract to replace the existing contract which was set to expire on November 1, 2006. We did not reach agreement on new contractual terms. Under terms of the existing agreement, it automatically extended until November 1, 2007 since neither party gave notice of cancellation as provided for in the existing agreement. We anticipate negotiations to commence in the summer of 2007 on a new contract.
On May 6, 2006, Aquila Union Locals 814 and 695 of the IBEW both ratified a new contract with EDG. This agreement brought three separate contracts into one new three-year agreement.
(1) See Item 6, Selected Financial Data for additional financial information regarding Empire.
(2) Includes Public Street & Highway Lighting and Public Authorities.
(3) Before intercompany eliminations.
(4) Includes KWh Used by Company and Interdepartmental KWh.
(5) Includes the effect of our unbilled revenue adjustment. (See Note 1 of Notes to Consolidated Financial Statements under Item 8).
(1) See Item 6, Selected Financial Data for additional financial information regarding Empire.
(2) Revenues represent the months of June through December 2006.
(3) mcf sales represent the months of June through December 2006.
The names of our officers, their ages and years of service with Empire as of December 31, 2006, positions held and effective date of such positions are presented below. All of our officers, other than Gregory A. Knapp and Laurie A. Delano (whose biographical information is set forth below), have been employed by Empire for at least the last five years.
(1) Bradley P. Beecher was elected Vice President and Chief Operating Officer Electric on June 1, 2006.
(2) Harold Colgin was elected Vice President Energy Supply on October 26, 2006.
(3) Ronald F. Gatz was elected Vice President and Chief Operating Officer Gas on June 1, 2006.
(4) Gregory A. Knapp was previously with Empire from 1978 to 2000 and held the position of Controller and Assistant Treasurer (1983). During the period from 2000 to 2002, Mr. Knapp served as Controller for the Missouri Department of Transportation.
(5) Kelly S. Walters was elected Vice President Regulatory and General Services on February 2, 2006, effective May 1, 2006.
(6) Laurie A. Delano was previously with Empire from 1979 to 1991 and held the position of Director of Internal Auditing (1983-1991). Immediately prior to rejoining Empire, she was with Lozier Corporation, a store fixture manufacturing company, from 1997 to 2002, where she served as Plant Controller.
General. As a public utility, our electric segment operations are subject to the jurisdiction of the MPSC, the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC) and the Arkansas Public Service Commission (APSC) with respect to services and facilities, rates and charges, accounting, valuation of property, depreciation and various other matters. Each such Commission has jurisdiction over the creation of liens on property located in its state to secure bonds or other securities. The KCC also has jurisdiction over the issuance of securities because we are a regulated utility incorporated in Kansas. Our transmission and sale at wholesale of electric energy in interstate commerce and our facilities are also subject to the jurisdiction of the FERC, under the Federal Power Act. FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale; the sale, lease or other disposition of such facilities and accounting matters. See discussion in Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Competition.
During 2006, approximately 91% of our electric operating revenues were received from retail customers. Approximately 87.6%, 6.1%, 3.0% and 3.3% of such retail revenues were derived from sales in Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales subject to FERC jurisdiction represented approximately 8% of our electric operating revenues during 2006 with the remaining 1% being from miscellaneous sources.
Rates. See Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Rate Matters for information concerning recent electric rate proceedings.
Fuel Adjustment Clauses. Typical fuel adjustment clauses permit the distribution to customers of changes in fuel costs without the need for a general rate proceeding. Fuel adjustment clauses are presently applicable to our retail electric sales in Oklahoma and Kansas (effective January 1, 2006) and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis. On July 14, 2005, Missouri Governor Blunt signed Bill SB 179 which authorizes the MPSC to grant fuel adjustment clauses for utilities in the state of Missouri. The bill went into effect January 1, 2006 and is now effective. We do not currently have a fuel adjustment clause in Missouri.
General. As a public utility, our gas segment operations are subject to the jurisdiction of the MPSC with respect to services and facilities, rates and charges, accounting, valuation of property, depreciation
and various other matters. The MPSC also has jurisdiction over the creation of liens on property to secure bonds or other securities.
Purchased Gas Adjustment (PGA). The PGA clause allows EDG to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies. A PGA clause is included in our rates which allows for the over recovery or under recovery resulting from the operation of the regular PGA section of the PGA clause and a calculation of the Annual Purchased Gas Adjustment. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.
We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. PGA factor elements considered include demand reserves, storage activity, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.
Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments), are reflected as a deferred charge or credit. The balance is amortized as amounts are reflected in customer billings.
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.
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.
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, 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 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 MDNRs 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.
Clean Air Interstate Rule 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 the 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 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 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 will be completed in March 2007. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded key sections of the EPAs 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 EPAs 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 sites 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.
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.
Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the EDE Mortgage), and our Restated Articles of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the 15 months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended December 31, 2006, would permit us to issue approximately $368.3 million of new first mortgage bonds based on this test at an assumed interest rate of 6.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2006, we had retired bonds and net property additions which would enable the issuance of at least $527.2 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2006, we are in compliance with all restrictive covenants of the EDE Mortgage.
Under our Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in our Restated Articles) for a specified twelve-month period is at least 1-1/2 times the sum of the annual interest requirements on all indebtedness and the annual dividend requirements on all cumulative preferred stock to be outstanding immediately after the issuance of such additional shares of cumulative preferred stock, and (b) so long as any preferred stock is outstanding, the amount of unsecured indebtedness outstanding may not exceed 20% of the sum of the outstanding secured indebtedness plus our capital and surplus. We have no outstanding preferred stock. Accordingly, the restriction in our Restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.
Our EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. At December 31, 2006, we had property additions of $0.7 million. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDGs ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1. As of December 31, 2006, this test would not allow us to issue any new first mortgage bonds as the gas segment has not been operational for a full year. Additionally, the transition service costs, although expected, negatively impact the EBITDA ratio, and the results of the gas segment also do not yet include a complete winter heating season.
We maintain a website at www.empiredistrict.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and related amendments are available free of charge through our website as soon as reasonably practicable after such reports are filed with or furnished to the SEC electronically. Our Corporate Governance Guidelines, our Code of Business Conduct and Ethics, our Code of Ethics for the Chief Executive Officer and Senior Financial Officers, the charters for our Audit Committee, Compensation Committee and Nominating/Corporate Governance Committee, our Procedures for Reporting Complaints on Accounting, Internal Accounting Controls and Auditing Matters, our Procedures for Communicating with Non-Management Directors and our Policy and Procedures with Respect to Related Person Transactions can also be found on our website. All of these documents are available in print to any interested party who requests them. Our website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K.
Currently, our corporate credit ratings and the ratings for our securities are as follows:
Fitch, Moodys and Standard & Poors currently have a stable outlook, a negative outlook and a stable outlook, respectively, on Empire.
These ratings indicate the agencies assessment of our ability to pay interest, distributions and principal on these securities. The lower the rating, the higher the interest cost of the securities when they are sold. In addition, downgrades in our senior unsecured long-term debt rating, under the terms of our revolving credit facility, result in an increase in our borrowing costs under that credit facility. To the extent any of our ratings fall below investment grade (investment grade is defined as Baa3 or above for Moodys and BBB- or above for Standard & Poors and Fitch), our ability to issue short-term debt, commercial paper or other securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on our business, financial condition and results of operations. On May 17, 2006, S&P lowered our senior unsecured debt rating to BB+ (a non-investment grade rating) from BBB-.
We cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.
We have established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs. Within this activity, we may incur losses from these contracts. These losses could have a material adverse effect on our results of operations.
By using physical and financial instruments, we are exposed to credit risk and market risk. Credit risk is the risk that the counterparty might fail to fulfill its obligations under contractual terms. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted cumulatively on a monthly basis until prescribed determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any realized gain or loss for that period related to the contract will be reclassified to fuel expense.
We are subject to comprehensive regulation by one federal and several state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where we operate regulate many aspects of our utility operations, including siting and construction of facilities, pipeline safety and compliance, customer
service, our ability to recover increases in our fuel and purchased power costs and the rates that we can charge customers.
FERC has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce. Federal, state and local agencies also have jurisdiction over many of our other activities.
Information concerning recent filings requesting increases in rates and related matters is set forth under Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Rate Matters.
We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Despite our requests, these regulatory commissions have sole discretion to leave rates unchanged, grant increases or order decreases in the base rates we charge our customers. They have similar authority with respect to our recovery of increases in our fuel and purchased power costs. In the event that our costs increase and we are unable to recover increased costs through base rates or fuel adjustment clauses, our results of operations could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have a material adverse effect on our results of operations.
A combination of increases in customer demand, decreases in output from our power plants and/or the failure of performance by purchased power contract counterparties could have a material adverse effect on our results of operations.
In the event that demand for power increases significantly and rapidly (due to weather or other conditions) and either our power plants do not operate as planned or the parties with which we have contracted to purchase power are not able to, or fail to, deliver that power, we would be forced to purchase power in the spot-market. Those unforeseen costs could have a material adverse effect on our results of operations. See Item 1, Business Fuel and Natural Gas Supply, Item 2, Properties Electric Segment Facilities and Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Electric Segment Operating Revenue Deductions for more information.
The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Mild weather reduces demand and, as a result, our electric operating revenues. Weather can also impact the revenues of our natural gas utility business. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our natural gas service territory and a significant amount of our natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our natural gas operations have historically generated less revenues and income when weather conditions are warmer in the winter.
The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, including repairs following severe weather, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Of the factors driving expenses, fuel and purchased power costs are our largest expense items. Increases in the price of natural gas or the cost of purchased power will result in increases in electric operating expenses. Our existing strategies for mitigating such risks include hedging against changes in natural gas prices and utilizing fuel adjustment mechanisms to recover actual fuel and purchased power expenses.
Such efforts, however, may not offset or permit us to recover all of such increased costs. Therefore, significant increases in electric operating expenses or reductions in electric operating revenues may occur and result in a material adverse effect on our business, financial condition and results of operations.
In our natural gas utility business, we are permitted to recover the cost of gas directly from our customers through the use of a purchased gas adjustment provision. However, this provision only permits the recovery of prudently-incurred costs. To the extent the MPSC determines that any of our costs were not prudently incurred, we would have to repay any such amounts that we collected from customers as part of an annual reconciliation. In addition, increases in natural gas costs affect total prices to our customers and, therefore, the competitive position of gas relative to electricity, other forms of energy and other gas suppliers. Increases in natural gas costs may also result in lower usage by customers unable to switch to alternate fuels. Any such disallowed costs or customer losses could have a material adverse effect on our results of operations.
We depend upon regular deliveries of coal as fuel for our Riverton, Asbury and Iatan plants, and as fuel for the facility which supplies us with purchased power under our contract with Westar Energy. Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to the plants by train. Production problems in these mines, railroad transportation or congestion problems, such as those that occurred in 2005 and 2006, or unavailability of trains could affect delivery cycle times required to maintain plant inventory levels, causing us to implement coal conservation and supply replacement measures to retain adequate reserve inventories at our facilities. These measures could include reducing the output of our coal plants, increasing the utilization of our gas-fired generation facilities, purchasing power from other suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can be delivered without using the railroads. Such measures could result in increases in our fuel and purchased power costs and could have a material adverse effect on our financial condition and results of operations.
We are subject to extensive federal, state and local regulation with regard to air and other environmental matters. Failure to comply with these laws and regulations could have a material adverse effect on our results of operations and financial position. In addition, new environmental laws and regulations, and new interpretations of existing environmental laws and regulations, have been adopted and may in the future be adopted which may substantially increase our future environmental expenditures for both new facilities and our existing facilities. Although we generally recover such costs through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases. The incurrence of additional material environmental costs which are not recovered in our rates may result in a material adverse effect on our business, financial condition and results of operations.
At December 31, 2006, we owned generating facilities with an aggregate generating capacity of 1,100 megawatts.
Our principal electric baseload generating plant is the Asbury Plant with 210 megawatts of generating capacity. The plant, located near Asbury, Missouri, is a coal-fired generating station with two steam turbine generating units. The plant presently accounts for approximately 19% of our owned generating capacity and in 2006 accounted for approximately 41% of the energy generated by us. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled once each year, normally for approximately four weeks in the spring. Due to a blade failure in February, the Asbury 2006 spring outage was moved to the first quarter with Asbury back on line by March 3, 2006. Approximately every fifth year, the maintenance outage is scheduled to be extended to a total of six weeks to permit inspection of the Unit No. 1 turbine. The last such outage took place from September 15, 2001 to December 17, 2001, a total of thirteen weeks. The 2001 five-year major generator turbine inspection was extended to allow for expanded boiler maintenance and the replacement of the control system. The next such outage is scheduled for the fall of 2007 and will also include the tie-in of an SCR. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was also inspected during the 2001 outage. As of December 31, 2006, Unit No. 2 has operated approximately 2,458 hours since its last turbine inspection. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel costs associated with replacement energy.
Our generating plant located at Riverton, Kansas, has two steam-electric generating units with an aggregate generating capacity of 92 megawatts and three gas-fired combustion turbine units with an aggregate generating capacity of 44 megawatts. The steam-electric generating units burn coal as a primary fuel and have the capability of burning natural gas. Unit No. 7 was taken out of service from October 1, 2005 to November 4, 2005 for its five-year scheduled maintenance outage. Unit No. 8 was taken out of service from February 14, 2003 to May 14, 2003 for its scheduled five-year maintenance outage as well as to make necessary repairs to a high-pressure cylinder. We have purchased, and are installing at our Riverton plant, a Siemens V84.3A2 combustion turbine (Unit 12) with an expected capacity of 155 megawatts to be operational in spring 2007. Testing on the new unit began on January 12, 2007.
We own a 12% undivided interest in the coal-fired Unit No. 1 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. Iatan 1 underwent a planned maintenance and turbine inspection from January 6, 2007 through February 23, 2007. 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 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. This heat input limit 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. We are entitled to 12% of the units available capacity and are obligated to pay for that percentage of the operating costs of the unit. KCP&L and Aquila own 70% and 18%, respectively, of the Unit. KCP&L operates the unit for the joint owners. On June 13, 2006, we entered into an agreement with KCP&L to purchase an undivided ownership interest in the new coal-fired Iatan 2. We will own 12%, or approximately 100 megawatts, of the new 850-megawatt unit to be operated by KCP&L and located at the site of the existing Iatan Generating Station.
Our State Line Power Plant, which is located west of Joplin, Missouri, presently consists of Unit No. 1, a combustion turbine unit with generating capacity of 89 megawatts and a Combined Cycle Unit with
generating capacity of 500 megawatts of which we are entitled to 60%, or 300 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc. which owns the remaining 40% of the unit. Westar reimburses us for a percentage of the operating costs. We are the operator of the Combined Cycle Unit. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the additional capability of burning oil. Unit No. 1 had its first major inspection from September 7, 2006 until December 20, 2006.
We have four combustion turbine peaking units, including two FT8 peaking units installed in 2003, at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 271 megawatts. These peaking units operate on natural gas, as well as oil. On January 7, 2004, one of the original combustion turbine peaking units, Unit No. 2, experienced a rotating blade failure. Upon dismantling and inspecting the unit, we found damage to rotating and stationary components in the turbine, as well as anomalies in the generator. We incurred $4.1 million of insurable costs to repair this facility, including a $1 million insurance deductible we expensed in the first quarter of 2004 related to this damage. We received all of the remaining $3.1 million from our insurer as of June 30, 2005.
Our hydroelectric generating plant, located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We replaced two of the four water wheels at our hydroelectric plant in 2003, the third wheel in early 2004 and the fourth and final wheel in March 2005. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in Southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of our average annual energy production. We expect that the Army Corp of Engineers will not implement the new minimum flow plan until at least 2009, but, at this time, cannot be sure of the timetable. The Appropriations Act has a provision for the Army Corp of Engineers to provide a one time payment to us for lost energy production. The Appropriations Act requires us, in coordination with our relevant public service commissions and the Southwest Power Administration, to determine our economic detriment. We expect the process for reaching agreement on our economic harm to extend through the end of 2007, but cannot predict the outcome at this time.
At December 31, 2006, our transmission system consisted of approximately 22 miles of 345 kV lines, 430 miles of 161 kV lines, 747 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,731 miles of line.
Our electric generation stations are located on land owned in fee. We own a 3% undivided interest as tenant in common with KCP&L and Aquila in the land for the Iatan Generating Station. We own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all of our electric segment property, plant and equipment are subject to the EDE Mortgage.
We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 86 miles of water mains in three communities in Missouri.
We acquired the Missouri natural gas distribution operations of Aquila, Inc. on June 1, 2006. These properties consist of customers in 44 Missouri communities in northwest, north central and west central
Missouri. At December 31, 2006, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,105 miles of distribution mains.
Substantially all of our gas transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all of our gas segment property, plant and equipment are subject to the EDG Mortgage.
Our other segment consists of our businesses which are unregulated and which we operate through our wholly-owned subsidiary EDE Holdings, Inc. As of December 31, 2006, we owned the following: a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business; a 100% interest in Utility Intelligence, Inc., a company that distributes automated meter reading equipment and a 100% interest in Fast Freedom, Inc., an Internet provider. In August 2006, we sold our controlling 52% interest in MAPP to other current owners. MAPP specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software.
See description of legal matters set forth in Note 12 of Notes to Consolidated Financial Statements under Item 8, which description is incorporated herein by reference.
Our common stock is listed on the New York Stock Exchange. On February 16, 2007, there were 5,519 record holders and 26,980 individual participants in security position listings. The high and low sale prices for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter of 2006 and 2005 were as follows:
Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefor subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings, which is essentially our accumulated net income less dividend payouts. As of December 31, 2006, our retained earnings balance was $22.9 million (compared to $19.7 million at December 31, 2005) after paying out $36.1 million in dividends during 2006. If we were to reduce our dividend per share, partially or in whole, it could have an adverse effect on our common stock price.
The Mortgage and the Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the earned surplus (as defined in the Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. As of December 31, 2006, our level of retained earnings did not prevent us from issuing dividends. In addition, under certain circumstances (including defaults thereunder), our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock.
During 2006, no purchases of our common stock were made by or on behalf of us.
Participants in our Dividend Reinvestment and Stock Purchase Plan may acquire, at a 3% discount, newly issued common shares with reinvested dividends. Participants may also purchase, at an averaged market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their stock certificates.
Our shareholders rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. One Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group (Acquiring Person)) will be exercisable only if an
Acquiring Person acquires 10% or more of our common stock or if certain other events occur. See Note 6 of Notes to Consolidated Financial Statements under Item 8 for additional information. In addition, we have stock based compensation programs which are described in Note 5 of Notes to Consolidated Financial Statements under Item 8.
Our By-laws provide that K.S.A. Sections 17-1286 through 17-1298, the Kansas Control Share Acquisitions Act, will not apply to control share acquisitions of our capital stock.
See Note 5 of Notes to Consolidated Financial Statements under Item 8 for additional information regarding our common stock and equity compensation plans.
The following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2001, in our common stock and similar investments made in the securities of the companies in the Standard & Poors 500 Composite Index (S&P 500 Index) and the Standard & Poors Electric Utilities Index (S&P Electric Utility). The graph and table assume that dividends were reinvested when received.
RETURN TO STOCKHOLDERS
(in thousands, except per share amounts)(1)
(1) All years presented have been adjusted to show continuing operations and to reflect the sale of MAPP and Conversant in 2006 as discontinued operations.
(2) Includes EDG data for the months of June through December 2006.
(3) Total assets at December 31, 2006 increased $30.0 million due to regulatory assets recorded upon adoption of FAS 158. (See Note 9 of Notes to Consolidated Financial Statements under Item 8).
(4) 2006 capital expenditures do not include $103.2 million for the acquisition of the Missouri Gas operations.
We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) 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 customers in 44 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 in our wholly-owned subsidiary, EDE Holdings, Inc. In 2006, 93.0% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 6.1% from the sale of gas and 0.9% from our non-regulated businesses. In August 2006, we sold our controlling 52% interest in MAPP, which specializes in close-tolerance custom manufacturing. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software. For financial reporting purposes, MAPP and Conversant have been classified as discontinued operations and are not included in our segment information.
The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and purchased power) and/or rate relief. We assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Weather affects the demand for electricity. Very hot summers and very cold winters increase electric demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and by general economic conditions. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual electric customer growth to range from approximately 1.6% to 1.9% over the next several years, although our electric customer growth for the twelve months ended December 31, 2006 was 2.1%. We define electric sales growth to be growth in kWh sales excluding the impact of weather. The primary drivers of electric sales growth are customer growth and general economic conditions.
The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, including repairs following severe weather, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Fuel and purchased power costs are our largest expense items. Several factors affect these costs, including fuel and purchased power prices, plant outages and weather, which drives customer demand. In order to control the price we pay for fuel for electric generation and purchased power, we have entered into long and short-term agreements to purchase power (including wind energy) and coal and natural gas for our energy supply. We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices.
The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline
transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for such relief when necessary. However, we have agreed with the MPSC to not file a rate increase request for non-gas costs prior to June 1, 2009. A PGA clause is included in our gas rates, which allows us to recover our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season. As a result, for the company as a whole we expect our acquisition of Missouri Gas to allow us to help diversify our weather risk, balancing our current summer air conditioning peak which drives higher electricity demand with a natural gas winter heating peak. Customer growth, which is the growth in the number of customers, contributes to the demand for gas. We expect our annual gas customer growth to range from approximately 1.1% to 1.8% over the next several years. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth are customer growth and general economic conditions.
The primary driver of our gas operating expense in any period is the price of natural gas. However, because gas purchase costs for our gas utility operations are normally recovered from our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent or causes customers to reduce usage.
For the twelve months ended December 31, 2006, basic and diluted earnings per weighted average share of common stock were $1.39 as compared to $0.92 for the twelve months ended December 31, 2005. As reflected in the table below, the primary positive drivers for this increase were increased electric revenues and decreased total electric fuel and purchased power costs.
The following reconciliation of basic earnings per share between 2005 and 2006 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current years. The reconciliation presents the after tax impact of significant items and components of the income statement on a per share basis before the impact of additional stock issuances which is presented separately. On-system electric revenues include approximately $8.7 million of the collected IEC which will not be refunded pursuant to the December 21, 2006 order from the MPSC. Earnings per share for the years ended December 31, 2005 and 2006 shown in the reconciliation are presented on a GAAP basis and are the same as the amounts included in the statements of operations. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.
* 2005 and 2006 include the effect of discontinued operations, which were losses of $0.04 and $0.02, respectively.
** Gas revenues and expenses are included from June 1, 2006.
Earnings for the fourth quarter of 2006 were $8.2 million, or $0.27 per share, compared to fourth quarter 2005 earnings of $1.3 million, or $0.05 per share. An increase in total revenues for the fourth quarter of 2006 contributed an estimated $0.50 per share as compared to the fourth quarter of 2005. Increased operating expenses, including fuel and purchased power, negatively impacted earnings an estimated $0.15 per share, while increased interest charges and the dilutive effect of additional shares reduced earnings an estimated $0.04 per share each and increased maintenance costs and increased general taxes reduced earnings an estimated $0.03 per share each.
On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties serve customers in 44 Missouri communities in northwest, north central and west central Missouri. The base purchase price was $85 million in cash, plus working capital and subject to net plant adjustments. This transaction was subject to the approval of the MPSC, which was obtained, effective May 1, 2006. We announced the completion of this acquisition on June 1, 2006. The total purchase price paid to Aquila, Inc., including working capital and net plant adjustments of $17.1 million, was $102.1 million, not including acquisition costs. As of December 31, 2006, the purchase price has been increased to $102.5 million for additional true-up items. The acquisition was initially financed by $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG, and with short-term debt issued by EDE. This short-term debt was repaid with the proceeds of the sale of shares of our common stock on June 21, 2006.
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. On December 12, 2006, KCP&L announced that the total estimated construction budget for Iatan 2, originally reported to be approximately $1.34 billion, had increased to a range of approximately $1.53 billion to $1.67 billion due to increases in estimated costs for labor, materials and equipment and also reflecting other market conditions. KCP&L, which will own 54.7% of the unit, announced their expected share of the total construction costs, originally reported to be approximately $733 million, would actually range from approximately $837 million to $914 million, due to the increase in estimated costs. Accordingly, our share of the Iatan 2 costs will increase from approximately $160.8 million to a range of approximately $183.6 million to $200.5 million. These estimated construction expenditures exclude AFUDC.
Our current capital expenditures budget includes $45.6 million in 2007, $85.0 million in 2008 and $64.7 million in 2009, including AFUDC, for our share of Iatan 2 with additional expenditures in 2010. At December 31, 2006, we have recorded approximately $12.4 million in construction expenditures on this project. As of December 12, 2006, KCP&L stated it had approximately 50% of the total estimated cost of Iatan 2 under firm contract and had started construction activities at the site. Iatan 2 is on schedule with completion targeted for 2010.
As a requirement for the air permit for Iatan 2 and to help meet CAIR and CAMR requirements, additional emission control equipment is required for Iatan 1. According to KCP&L, Iatan 1 environmental upgrades are on schedule, with approximately 69% of the total estimated costs under firm contract as of December 31, 2006. Our share of the environmental upgrade costs at Iatan 1 is estimated at $49 million, including AFUDC, and will be expended between 2006 and May 2009. At December 31, 2006, we have spent approximately $3.9 million on this project.
On March 14, 2006, we entered into contracts to add 100 megawatts of power to our system. This power will come from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for 2010. Initially we will own, through an undivided interest, 50 megawatts of the projects capacity for approximately $103 million in direct costs, including AFUDC. We also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. We spent $19.6 million through December 31, 2006 and anticipate spending an additional $25.8 million in 2007,
$28.6 million in 2008 and $19.2 million in 2009 for construction expenses (including AFUDC) related to our 50 megawatt ownership share of Plum Point Unit 1 with additional expenditures in 2010.
Plum Point Unit 1 and Iatan 2 are important components of a long-term, least-cost resource plan to add coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area and the expiration of a major purchased power contract in 2010.
Testing on our new 155 megawatt Siemens V84.3A2 combustion turbine at Riverton began on January 12, 2007. The unit is scheduled to be operational in the spring of 2007.
Coal conservation was not a major factor in the third and fourth quarters of 2006 at any of our coal-fired resources (Asbury, Riverton, Iatan or Westar Energy, with whom we have a purchased power contract). Our coal inventory levels at Riverton are still somewhat below target levels due to railroad transportation problems delivering Western coal but our inventory situation has improved and stabilized. As of December 31, 2006, we had sufficient coal to run approximately 36 days at our Riverton plant compared to 27 days as of December 31, 2005. As of December 31, 2006, we had approximately 79-83 days (depending on the actual blend ratio) of Western coal inventory at our Asbury plant, compared to approximately 27-40 days, as of December 31, 2005. Our average coal inventory target is 60 days at both plants. Rail transportation issues have also improved at Iatan, although Iatans coal supply continues to be below normal target levels.
On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29,513,713, or 9.63%. We requested transition from the IEC to Missouris new fuel adjustment mechanism. The MPSC issued an order on December 21, 2006 granting us an annual increase of $29,369,397 (including regulatory amortization), or 9.96%, with an effective date of January 1, 2007 and eliminating the IEC, pursuant to the December 21, 2006 order from the MPSC. This increase included an authorized return on equity of 10.9% and included fuel and energy costs as a component of base electric rates. Of the increase, approximately $19 million was granted in the form of base rates, with the remainder of approximately $10.4 million granted as regulatory amortization to provide additional cash flow to enhance the financial support for our current generation expansion plan. The amortization component will not affect earnings, however, since there will be an offsetting expense recorded. This order also allowed deferral of any Postretirement Employee Benefit Costs (OPEB) that are different from those allowed recovery in this rate case. This treatment is similar to treatment afforded pension costs in our March 2005 rate case. This order also approved regulatory treatment of additional liabilities arising from the adoption of FASB No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132R (FAS 158). We also agreed to write off $1 million of the cost of our Energy Center 2 construction project. The Missouri jurisdictional portion of this agreement resulted in a pre tax write off of $0.8 million in the fourth quarter of 2006.
On December 29, 2006, the Office of Public Counsel (OPC) and intervenors Praxair, Inc. and Explorer Pipeline Company, filed an application with the MPSC requesting the MPSC grant a rehearing on most of the issues addressed in the December 2006 Missouri rate case order and many of the procedural issues. On December 29, 2006, we also filed an application with the MPSC requesting a rehearing on return on equity, capital structure and energy cost recovery. A decision by the MPSC is pending.
Praxair and Explorer Pipeline filed a Petition for Writ of Review with the Cole County Circuit Court on January 31, 2007. The Circuit Court issued a Writ, but the MPSC has moved to have the Writ set aside and the case dismissed. The MPSCs motion to set aside the Writ is still pending. Additionally, on January 4, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Court of Appeals,
Western District. We filed suggestions in opposition to the Petition, as did the Staff of the MPSC. The OPCs Petition is still pending.
For additional information, see Rate Matters below.
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. We preliminarily estimated the cost of property damage and reconstruction expense to be in the range of $20 to $23 million. However, our updated estimate is approximately $26 million although the exact cost and the determination of how much of the cost will be capitalized as construction expenditures are not yet known. The impact on earnings per share for the first quarter of 2007 is likely to be material. We expect to request recovery of all or some of these costs from the commissions in our jurisdictions in future rate cases. We cannot predict the outcome of such requests.
The following discussion analyzes significant changes in the results of operations for the years 2006, 2005 and 2004.
The following table represents our results of operations by operating segment for the applicable periods ended December 31:
Our electric segment income from continuing operations for 2006 was $40.7 million as compared to $24.9 million for 2005.
Electric operating revenues comprised approximately 92.6% of our total operating revenues during 2006. Of these total electric operating revenues, approximately 41.7% were from residential customers, 30.1% from commercial customers, 16.9% from industrial customers, 4.6% from wholesale on-system customers, 3.2% from wholesale off-system transactions and 3.5% from miscellaneous sources, primarily transmission services. The breakdown of our electric customer classes has not significantly changed from 2005 or 2004.
The amounts and percentage changes from the prior periods in kilowatt-hour (kWh) sales and operating revenues by major customer class for on-system sales were as follows:
* Percentage changes are based on actual kWh sales and revenues and may not agree to the rounded amounts shown above.
** Other kWh sales and other operating revenues include street lighting, other public authorities and interdepartmental usage.
2006 Compared to 2005
KWh sales for our on-system customers increased approximately 2.6% during 2006 as compared to 2005 primarily due to continued sales growth. Revenues for our on-system customers increased approximately $25.8 million, or 7.6%. The January 2006 Kansas rate increase, March 2005 Missouri rate increase and May 2005 Arkansas rate increase (discussed below) contributed an estimated $13.8 million to revenues in 2006 while continued sales growth contributed an estimated $6.9 million. Additionally, revisions to our estimate of unbilled revenues contributed $5.9 million to revenues in 2006. Weather and other factors had a negative impact of an estimated $2.8 million despite our setting a new record summer peak of 1,159 megawatts on July 19, 2006. The collected IEC, which will not be refunded pursuant to the December 21, 2006 order from the MPSC, contributed approximately $2.0 million more during 2006. Our customer growth was 2.1% in 2006 compared to 1.9% in 2005. We expect our annual customer growth to range from approximately 1.6% to 1.9% over the next several years.
Residential and commercial kWh sales increased in 2006 primarily due to the strong sales growth and the increase from our revisions to our estimate of unbilled revenues while the associated revenues also increased due to the Missouri, Arkansas and Kansas rate increases. Industrial kWh sales increased 3.5% while revenues increased 8.8%, reflecting the increased sales growth and the aforementioned rate increases. On-system wholesale kWh sales increased reflecting the continued sales growth discussed above. Revenues associated with these FERC-regulated sales increased more than the kWh sales as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs.
In addition to sales to our own customers, we also sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers. See Competition below. The following table sets forth information regarding these sales and related expenses for the years ended December 31: