ITEM 1. BUSINESS
General
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.
Electric Generating Facilities and Capacity
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, “Management’s 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 project’s 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 SPP’s 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, “Management’s 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.
Gas Facilities
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:
South - Southern Star Central Gas Pipeline
North - Panhandle Eastern Pipe Line Company
NW - ANR Pipeline Company
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.
Construction Program
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, “Management’s 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, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Competition.”
Fuel and Natural Gas Supply
Electric Segment
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 Iatan’s 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.
Gas Segment
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:
Employees
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.
ELECTRIC OPERATING STATISTICS(1)
(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).
GAS OPERATING STATISTICS(1)
(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.
Executive Officers and Other Officers of Empire
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.
Regulation
Electric Segment
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, “Management’s 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, “Management’s 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.
Gas Segment
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.
Environmental Matters
We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and wastes, including their identification, transportation, disposal, record-keeping and reporting, including asbestos, as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.
Electric Segment
Air. The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan Power Plants and Units 3 and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx). The Asbury Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired boiler on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an affected unit for SO2 and NOx on January 1, 2000. Units 3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003. The new Riverton Unit 12 became an affected unit in January 2007.
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 MDNR’s Missouri NOx Rule, our Iatan, Asbury, State Line and Energy Center facilities, like other facilities in Western Missouri, are generally subject to a maximum NOx emission rate of 0.35 lbs/mmBtu. However, facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are only subject to a higher NOx emission limit of 0.68 lbs/mmBtu. All of our plants currently meet the required emission limits and additional NOx controls are not required.
NOx is further regulated as described in the Clean Air Interstate Rule below.
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 EPA’s February 16, 2004 regulations. At this time, the schedule for reconsideration and revisions is not known. We will be engaged with the EPA in its reconsideration and revision process. Data collection will continue under the PIC and will be expanded as needed to limit increased costs, if any, due to the EPA’s reconsiderations. At this time, we do not expect costs associated with compliance to be material.
Other. Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for
five years, regulate the plant site’s total emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Plants. We submitted the required renewal applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan is required by the renewed permit for Asbury. We estimate that the capital costs associated with the CAM plan will not exceed $2 million.
A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts and, as a result, our share decreased from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and baghouse are completed, currently estimated to be late in the fourth quarter of 2008.
Gas Segment
The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri (the MDNR Registry). Site #2 has received a letter of no further action from the MDNR. We are reviewing various actions that may be undertaken to reduce environmental and health risks associated with the MDNR Registry site.
Conditions Respecting Financing
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, EDG’s 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.
Our Website
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.
ITEM 1A.
ITEM 1A. RISK FACTORS
Any reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.
Currently, our corporate credit ratings and the ratings for our securities are as follows:
Fitch, Moody’s and Standard & Poor’s 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 Moody’s and BBB- or above for Standard & Poor’s 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 are exposed to market risk in our fuel procurement strategy and may incur losses from these activities.
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 regulation in the jurisdictions in which we operate.
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, “Management’s 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, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Electric Segment - Operating Revenue Deductions” for more information.
We are exposed to increases in costs and reductions in revenue which we cannot control and which may adversely affect our business, financial condition and results of operations.
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.
We may be unable to recover increases in the cost of natural gas from our natural gas utility customers, or may lose customers as a result of any price increases.
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.
Disruptions in coal deliveries could require us to reduce the output of our coal-fired generating facilities and lead to increases in our fuel and purchased power costs.
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 environmental laws and the incurrence of environmental liabilities which may adversely affect our business, 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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Electric Segment Facilities
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 unit’s 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.
Gas Segment Facilities
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.
Other Segment Businesses
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.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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 & Poor’s 500 Composite Index (S&P 500 Index) and the Standard & Poor’s Electric Utilities Index (S&P Electric Utility). The graph and table assume that dividends were reinvested when received.
TOTAL RETURN TO STOCKHOLDERS
(Assumes $100 investment on 12/31/01)
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(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.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
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.
Electric Segment
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.
Gas Segment
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.
Earnings
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.
2006 Activities
Missouri Gas
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.
Energy Supply
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 project’s 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 Iatan’s coal supply continues to be below normal target levels.
Regulatory Matters
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 Missouri’s 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 MPSC’s 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 OPC’s Petition is still pending.
For additional information, see “Rate Matters” below.
Subsequent Events
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.
RESULTS OF OPERATIONS
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:
Electric Segment
Overview
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
Operating Revenues and Kilowatt-Hour Sales
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.
Off-System Electric Transactions
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:
Revenues less expenses decreased during 2006 as compared to 2005 due to decreased market demand resulting from mild weather in the first quarter of 2006 as well as less market demand for gas-fired energy in the third quarter of 2006 as compared to the third quarter of 2005 when there was a shortage of available coal-fired generation on the open market. Companies that normally would have coal-fired energy to sell in the market were not doing so due to coal shortages, pushing demand onto the gas-fired units. The related expenses are included in our discussions of purchased power costs below.
Operating Revenue Deductions
During 2006, total electric segment operating expenses increased approximately $10.1 million (3.3%) compared to 2005. Total fuel costs decreased approximately $18.8 million (16.7%) during 2006 partially offset by increased purchased power costs of approximately $13.6 million (25.8%), resulting in a net decrease of $5.2 million for fuel and purchased power. The decrease in fuel costs was primarily due to decreased generation by our gas fired units during 2006 as compared to 2005 (an estimated $25.6 million), partially offset by higher prices for both hedged and unhedged natural gas that we burned in our gas-fired units in 2006 (an estimated $4.4 million). In addition, in 2005 we recognized a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Increased coal costs contributed approximately $2.4 million to total fuel costs in 2006 and increased coal generation added approximately $2.0 million. A decrease in fuel oil generation decreased fuel costs approximately $2.0 million. The increase in purchased power costs primarily reflected our increased purchases from the Elk River Windfarm, LLC and also reflected a February 2006 outage at our Asbury plant.
Regulated - other operating expenses for our electric segment increased approximately $0.4 million (0.7%) during 2006 as compared to 2005 primarily due to increases of $0.7 million in professional services expense, $0.6 million in general labor costs and $0.5 million in customer assistance expense, partially offset by a $1.5 million decrease in employee health care costs. We began deferring a portion of our pension cost into a regulatory asset effective with the second quarter of 2005, as authorized in our 2005 Missouri rate case. We have deferred approximately $2.4 million as of December 31, 2006. See Note 9 of “Notes to Consolidated Financial Statements” under Item 8 for further discussion regarding our pension and post-retirement benefit plans.
Maintenance and repairs expense increased approximately $1.2 million (5.7%) during 2006 as compared to 2005 primarily reflecting increases of approximately $1.5 million in distribution maintenance costs and $1.4 million in maintenance costs for our gas-fired units, partially offset by a decrease of approximately $1.5 million in maintenance costs for our coal-fired units. The $1.4 million increase in maintenance for our gas-fired units consisted mainly of a $1.5 million increase in maintenance for our SLCC plant related to the spring 2006 maintenance outage and a $0.4 million increase in maintenance at our State Line Unit 1 plant, which had its first major inspection from September 7, 2006 until
December 20, 2006. These increases were partially offset by a $0.5 million decrease in maintenance during 2006 at our Energy Center plant related to generator repairs in the second quarter of 2005. The $1.5 million decrease in maintenance costs for our coal-fired units consisted mainly of a $0.9 million decrease in maintenance costs at our Riverton Plant and a $0.5 million decrease in maintenance costs at our Iatan plant related to 2005 outages.
Depreciation and amortization expense increased approximately $2.6 million (7.6%) during 2006 primarily due to higher depreciation rates that became effective on March 27, 2005 and increased plant in service. Other taxes increased approximately $0.5 million (2.5%) during 2006 due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes. Total provision for income taxes increased approximately $9.8 million (78.3%) during 2006 as compared to 2005 mainly due to higher taxable income.
2005 Compared to 2004
Operating Revenues and Kilowatt-Hour Sales
KWh sales for our on-system customers increased approximately 6.4% during 2005 primarily due to continued sales growth and favorable weather conditions with a then record summer peak of 1,087 megawatts set on July 22, 2005 and a new record winter peak of 1,031 megawatts set on December 9, 2005. Revenues for our on-system customers increased approximately $50.2 million, or 17.3%. The March 2005 Missouri rate increase and May 2005 Arkansas rate increase contributed an estimated $24.8 million to revenues in 2005 while continued sales growth contributed an estimated $8.3 million. Weather and other factors contributed an estimated $10.5 million and the collected IEC, which will not be refunded pursuant to the December 21, 2006 order from the MPSC, contributed approximately $6.7 million during 2005. Our customer growth was 1.9% in 2005 compared to 1.7% in 2004.
Residential and commercial kWh sales and associated revenues increased in 2005 due mainly to warmer temperatures in the second and third quarters of 2005 and colder temperatures in the fourth quarter of 2005 as compared to 2004, continued sales growth and the 2005 Missouri and Arkansas rate increases. Industrial kWh sales, which are not particularly weather sensitive, increased 2.0% while revenues increased 14.9%, reflecting the increased sales growth and the 2005 rate increases. On-system wholesale kWh sales increased, reflecting the weather conditions and 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.
Off-System Electric Transactions
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:
Revenues less expenses during 2005 were higher as compared to 2004 primarily due to increased sales of our gas-fired generation in the third and fourth quarters of 2005 due to a shortage of available coal-fired generation on the open market. Companies that normally would have coal-fired energy to sell in the market were not doing so due to coal shortages, pushing demand onto the gas-fired units. The related expenses are included in our discussions of purchased power costs below.
Operating Revenue Deductions
During 2005, total operating expenses increased approximately $59.0 million (21.5%) compared to 2004. Total fuel costs increased approximately $48.3 million (75.0%) during 2005 but were offset slightly by a small decrease in total purchased power costs of approximately $0.1 million (0.2%), resulting in a net increase of $48.2 million for fuel and purchased power. The increase in fuel costs was primarily due to higher prices for both hedged and unhedged natural gas that we burned in our gas-fired units in 2005 (an estimated $27.1 million) combined with increased generation by our gas fired units during 2005 as compared to 2004 (an estimated $15.9 million). Increased coal costs contributed approximately $3.3 million to the total fuel increase. Increased coal generation added approximately $0.2 million and increased fuel oil generation added $1.9 million. These increased costs reflect a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Natural gas prices increased in 2005, in part, from the effects of hurricane activity in the Gulf of Mexico. The increased usage was due in part to weather, as well as changes in the wholesale market impacted by coal delivery issues in the Midwest. The decrease in purchased power costs primarily reflected a shift from serving our energy needs with purchased power to generating our own power reflecting that it was more economical to run our own generating units during 2005 than to purchase power.
Regulated - other operating expenses increased approximately $1.2 million (2.3%) during 2005 as compared to 2004 primarily due to a $0.7 million increase in employee health care costs, an approximate $0.5 million increase in employee pension expense, a $0.6 million increase in professional services expense and a $0.7 million increase in transmission and distribution expense. These increases were partially offset by a $0.5 million decrease in stock compensation costs, a $0.5 million decrease in general administrative expense due to reduced costs associated with Sarbanes-Oxley Section 404 compliance, and a $0.3 million decrease in other power supply expenses. As discussed previously, effective with the second quarter of 2005, we began deferring a portion of our pension cost into a regulatory asset as authorized in our 2005 Missouri rate case. We had deferred approximately $1.5 million as of December 31, 2005. Our accumulated pension benefit obligation (ABO) was higher than the fair value of our plan assets at December 31, 2005. Therefore, we elected to make an additional cash contribution of $11.5 million to our pension plan in 2005. This cash contribution had no effect on net income. See Note 9 of “Notes to Consolidated Financial Statements” under Item 8 for further discussion regarding our pension and post-retirement benefit plans.
Maintenance and repairs expense increased approximately $0.1 million (0.4%) during 2005 as compared to 2004. Although maintenance and repairs expense was up a total of $0.7 million at our coal-fired plants in 2005 and transmission and distribution maintenance expense was up $0.3 million, these increases were offset by a $1.1 million decrease in maintenance and repairs expense at the Energy Center. The decrease in maintenance and repairs expense at the Energy Center in 2005 was primarily due to the $1.0 million insurance deductible recorded to expense in the first quarter of 2004 related to maintenance on the Energy Center’s Unit No. 2 following a rotating blade failure on January 7, 2004 and to the second and third quarter maintenance costs related to repairs at the Energy Center not subject to insurance recovery.
Depreciation and amortization expense increased approximately $4.9 million (15.8%) during 2005 primarily due to higher depreciation rates that became effective on March 27, 2005. Other taxes increased approximately $1.3 million (7.0%) during 2005 due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes. Total provision for income taxes increased approximately $1.0 million (8.6%) during 2005 as compared to 2004 mainly due to higher taxable income.
Gas Segment
Gas Segment Operating Revenues and Sales
During 2006 (June 1, 2006 - December 31, 2006), our total natural gas revenues were approximately $25.1 million. For the fourth quarter of 2006, our total natural gas revenues were approximately $18.6 million. The winter months are high sales months for the natural gas business, whose heating season runs from November to March of each year.
The following table details our natural gas sales and revenues for the periods ended December 31, 2006:
Total gas delivered to customers - mcf Sales
* mcf sales represent the months of June through December 2006.
Operating Revenues ($ in millions)
* Revenues represent the months of June through December 2006 and exclude forfeited discounts, reconnect fees, miscellaneous service revenues, etc.
Gas Segment Operating Revenue Deductions
During the fourth quarter of 2006, EDG’s cost of natural gas sold and transported was approximately $12.3 million. For the year-to-date, June 2006 through December 2006, EDG’s cost of natural gas sold and transported was approximately $15.3 million. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on income. Our Purchased Gas Adjustment (PGA) Clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs associated with the use of financial instruments to hedge the purchase price of natural gas.
Total other operating expenses were $2.4 million for the fourth quarter of 2006 and $5.6 million for the year-to-date, June 2006 through December 2006. EDG had net income of $0.7 million for the fourth quarter of 2006 and a net loss of $0.7 million for the year-to-date, June 2006 through December 2006, primarily due to transition costs paid to Aquila, Inc. during this period. We paid approximately $1.2 million in transition costs to Aquila, Inc. in 2006 for billing and other transition services. All services were transitioned by November 1, 2006.
Other Segment
Our other segment includes leasing of fiber optics cable and equipment (which we are also using in our own operations), Internet access and distribution of automated meter reading equipment. 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. We have reported MAPP’s and Conversant’s results as discontinued operations. See Note 18 of “Notes to Consolidated Financial Statements”. The following table represents our results of continuing operations for our remaining non-regulated businesses for the applicable periods ended December 31:
We evaluated our remaining other segment businesses for impairment at December 31, 2006 and believe, based on this analysis, that no impairment exists based on our forecast of future net cash flows. However, failure to achieve forecasted cash flows could result in impairment in the future.
Consolidated Company
Our consolidated provision for income taxes increased approximately $9.3 million during 2006 as compared to 2005. Our consolidated effective federal and state income tax rate for 2006 was 35.3% as compared to 33.4% for 2005. The increase in the effective tax rate for 2006 compared to 2005 was mainly due to increased income. In addition, an adjustment for the difference between the amount shown on the income tax returns and the amount accrued for the year 2005 was recorded in the third quarter of 2006, accounting for approximately 0.3% of the 1.9% increase.
Our consolidated provision for income taxes increased approximately $0.4 million during 2005 as compared to 2004 due primarily to higher taxable income. Our consolidated effective federal and state income tax rate for 2005 was 33.4% as compared to 34.1% for 2004.
See Note 10 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding income taxes.
Other Information
Nonoperating Items
Total allowance for funds used during construction (AFUDC) increased $3.7 million in 2006 as compared to 2005 and increased $0.3 million in 2005 as compared to 2004 due to higher levels of construction in each period. See Note 1 of “Notes to Consolidated Financial Statements” under Item 8.
Total interest charges on long-term debt increased $2.0 million (8.4%) in 2006 as compared to 2005 reflecting interest on the first mortgage bonds issued June 1, 2006 by EDG to fund a portion of our acquisition of the Missouri natural gas distribution operations from Aquila, Inc. Total interest charges on long-term debt decreased $0.6 million (2.4%) in 2005 as compared to 2004 primarily reflecting the refinancing we completed in June 2005 by calling a higher interest debt issue and replacing it with a debt issue at a lower interest rate. See “- Liquidity and Capital Resources” for further information. Short-term debt interest increased $2.1 million during 2006 as compared to 2005 and increased $0.2 million during 2005 as compared to 2004, reflecting increased usage of short-term debt in each period.
Losses from discontinued operations were approximately $0.6 million and $1.0 million in 2006 and 2005, respectively, which included operations and gains recognized from the sales of MAPP and Conversant.
Other Comprehensive Income
The change in the fair value of the effective portion of our open gas contracts for our electric business and our interest rate derivative contracts and the gains and losses on contracts settled during the periods being reported, including the tax effect of these items, are reflected in our Consolidated Statement of Comprehensive Income. This net change is recorded as accumulated other comprehensive income in the capitalization section of our balance sheet and does not affect net income or earnings per share. All of these contracts have been designated as cash flow hedges. The unrealized gains and losses accumulated in other comprehensive income are reclassified to fuel, or interest expense, in the periods in which the hedged transaction is actually realized or no longer qualifies for hedge accounting.
The following table sets forth the pre-tax gains/(losses) of our natural gas for our electric segment and interest rate contracts settled and reclassified, the pre-tax change in the fair market value (FMV) of our open contracts and the tax effect in Other Comprehensive Income for the presented periods ended December 31(in millions):
(1) Reflected in fuel expense
Our average cost for our open financial natural gas hedges was $4.805/Dth at December 31, 2006, $4.744/Dth at December 31, 2005 and $4.795/Dth at December 31, 2004.
We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting our 5.8% Senior Notes due 2035 prior to their issuance on June 27, 2005. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes. The $1.2 million redemption premium paid in connection with the redemption of the $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 redeemed in
June 2005, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. See Note 7 of “Notes to Consolidated Financial Statements” under Item 8. We had no interest rate derivative contracts in 2004 or 2006.
RATE MATTERS
We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.
Electric Segment
The following table sets forth information regarding electric and water rate increases since January 1, 2004:
Missouri
On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. On December 22, 2004, we, the MPSC Staff, the Office of the Public Counsel (OPC) and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above or below the amount included in this rate case as a regulatory asset or liability. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.
The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates included a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC was $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, an assessment would be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts was greater than $10 million, the excess over $10 million would be refunded to the customers. The entire excess amount of IEC, not previously refunded, would be refunded at the end of three years, unless the IEC was terminated earlier. Each refund was to include interest at the current prime rate at the time of the refund. The IEC revenues recorded since the inception of the IEC did not recover all the Missouri related fuel and purchased power costs incurred during that period. From inception of the IEC through December 31, 2006, the costs of fuel and purchased
power were approximately $22.3 million higher than the total of the costs in our base rates and the IEC recorded during the period, therefore, no provision for refund was recorded.
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 also requested transition from the IEC to Missouri’s new fuel adjustment mechanism. The MPSC issued an order May 2, 2006, however, ruling that we may have the option of requesting that the IEC be terminated, but we may not request the implementation of an energy cost recovery mechanism while the current IEC is effective. 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 this order, the collected IEC will not be refunded. The increase included an authorized return on equity of 10.9% and included our 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. This regulatory amortization is related to our investment in Iatan 2 and also includes our Riverton V84.3A2 combustion turbine (Unit 12) and the environmental improvements and upgrades at Asbury and Iatan 1. This order also allowed deferral of any OPEB that is 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 FAS 158. (See Note 1 for additional information).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 MPSC’s 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 OPC’s Petition is still pending.
On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.
Arkansas
On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005.
Kansas
On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our 2005 Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in this rate case as a regulatory asset or liability. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006. We made this filing on March 30, 2006 and are awaiting a response from the KCC.
Gas Segment
On June 1, 2006, The Empire District Gas Company acquired the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of 44 Missouri communities in northwest, north central and west central Missouri. The rates, excluding the cost of gas, are the same as had been in effect at Aquila, Inc. We agreed in the unanimous stipulation and agreement filed with the MPSC on March 1, 2006 and approved on April 18, 2006, to not file a rate increase request for non-gas costs for a period of 36 months following the closing date of the acquisition. We have also agreed to use Aquila Inc.’s current depreciation rates and were allowed to adopt the pension cost recovery methodology approved in our electric Missouri Rate Case effective March 27, 2005.
A PGA clause is included in our gas rates which allows for the over recovery or under recovery of actual gas costs compared to the cost of gas in the PGA rate. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions, natural gas prices and supply demands, rather than in one possibly extreme change per year. The Actual Cost Adjustment (ACA) is a scheduled yearly filing with the MPSC filed between October 15 and November 4 each year. This filing establishes the amount to be recovered from customers for the over/under recovered yearly amounts. A PGA is included in the ACA filing. An optional PGA filing without the ACA can be filed up to three times each year, provided a filing does not occur within 60 days of a previous filing. Our ACA filing was completed on November 3, 2006.
COMPETITION
Electric Segment
SPP-RTO
In 2003, 2004 and 2005, we filed notices of intent with the Southwest Power Pool Regional Transmission Organization (SPP RTO) for the right to withdraw from the SPP RTO effective November of the succeeding year. These notices were given primarily because of uncertainty surrounding the treatment from the states regarding RTO participation and cost recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind these notices, which we have done as recently as October 31, 2006. Because we have now obtained regulatory authorizations from Missouri, Kansas and Arkansas for continued participation in and transfer of functional control of our transmission facilities to the SPP RTO, coupled with the fact that a twelve month withdrawal notice can be submitted to the SPP RTO at any time, we have not filed a notice of intent to withdraw at this time.
On June 13, 2006, the MPSC issued an order approving the Stipulation and Agreement regarding our continued participation in and transfer of functional control of certain transmission facilities to the SPP RTO. Due to needed clarifications regarding the MPSC order, the parties to the agreement, except for the OPC, filed a Motion to Clarify. The Motion to Clarify was granted, and an Amended Order approving the Stipulation and Agreement was issued by the MPSC on July 13, 2006 with an effective date of July 23, 2006. As a condition of the MPSC approval of the Stipulation and Agreement, a Transmission Service Agreement (TSA) between us and the SPP RTO was to be filed and accepted by the FERC. Such filing was made to the FERC on July 31, 2006. During the FERC staff’s review of the filing, it was determined that a revision to our 2002 network integration transmission service agreement and network operating agreement with SPP RTO was necessary to reflect the existence of the TSA. On November 22, 2006, the SPP RTO made a filing of the revised agreements. On January 16, 2007, FERC issued a letter order accepting the revised network and operating agreements and the TSA as approved by the MPSC.
On July 14, 2006, we jointly filed an uncontested Stipulation and Agreement between ourselves, the other Kansas transmission owning utilities, interveners, and the KCC staff regarding a similar authorization to continue participation in the SPP RTO and transfer functional control of our transmission facilities. An order from the KCC approving the Stipulation and Agreement (i.e. our continued participation in the SPP RTO and transfer of functional control of certain transmission facilities) was issued on September 19, 2006.
On November 4, 2005, we filed a request for authorization from the Arkansas Public Service Commission (APSC) for the continued participation in the SPP RTO and transfer of functional control of certain transmission facilities. This filing was later combined with similar filings of Oklahoma Gas and Electric and American Electric Power - Southwestern Electric Power Company as well as the filing for the Certificate of Public Convenience and Necessity of the SPP RTO. On August 10, 2006, the APSC approved the consolidated filing, including ours, with certain reporting conditions.
FERC’s order regarding the MPSC TSA completes our efforts of obtaining the necessary state and federal regulatory approvals to transfer functional control of certain transmission facilities to the SPP RTO and continue our participation in the SPP RTO.
FERC Order No. 2000 requires RTOs to provide real-time energy imbalance services and a market-based mechanism for congestion management. The start of the SPP RTO energy imbalance services market (EIS) was delayed several times in 2006 due to the lack of SPP and market participant readiness. The SPP RTO recently finalized its initial market rules and readiness for implementation and certified its readiness to FERC on December 22, 2006. Additional EIS related filings at the FERC were made by the SPP RTO. On February 1, 2007, the SPP RTO launched its EIS market. 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.
FERC Market Power Order
In April and July 2004, FERC issued orders regarding new testing standards for assessing market power by entities that have wholesale market-based rate tariffs filed with the FERC. The parameters included in the tests are such that most investor owned electric utilities fail the test within their own control area and are subject to a rebuttable presumption of market power. Entities with wholesale market based rates tariffs are subject to a triennial filing to test for market power and are required to apply the new testing criteria. FERC determination of market power would result in the inability for a utility to continue to charge such market-based rates. In September 2004, we submitted amended and updated market power analyses filings.
On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control area based on our failure to meet one of FERC’s wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC issued its order accepting Empire’s proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders issued since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff applies only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, which could amount to approximately $0.6 million (excluding interest) covering over a thousand hourly energy sales over the past 18 months to numerous counterparties external to our system. In response to the order, we filed a Motion For Extension of time and expedited treatment regarding the refund and requested that such refund be delayed until 15 days after the FERC’s order on our rehearing request. On September 5, 2006, the FERC granted the Motion For Extension, as requested.
On September 14, 2006, we filed a Request For Rehearing of FERC’s August 15 order regarding the refund and market power mitigation we had proposed. We requested a rehearing and a waiver of the refund requirement in its entirety. At this time, we cannot predict the outcome of these proceedings.
Approximately 4.6% of our electric operating revenues in both 2006 and 2005 were derived from sales to on-system wholesale customers, the type of customer for which the FERC is already requiring wheeling, or the use, for a fee, of transmission facilities owned by one company or system to move electrical power for another company or system. Our two largest on-system wholesale customers accounted for 92% of our wholesale business in 2006. We have contracts with these customers through the first quarter of 2008.
Gas Segment
Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.
LIQUIDITY AND CAPITAL RESOURCES
Our net cash provided by operations was slightly higher in 2006 as compared to 2005. Investments were higher due to increased construction and our acquisition of Missouri Gas. Our primary sources of cash flow during 2006 were $76.3 million in internally generated funds, $79.3 million in proceeds from issuance of common stock, $55.0 million in proceeds from the sale of EDG first mortgage bonds and $46.1 million in net proceeds from short-term debt. Our primary uses of cash during 2006 were $120.2 million in capital expenditures, $103.2 million for our acquisition of Missouri Gas and $36.1 million in dividend payments.
Our capital expenditures are expected to continue to increase during 2007, 2008 and 2009 due to our portion of the construction for the Plum Point Unit 1 and Iatan 2 power plants as well as the remainder of the expenditures for the Siemens V84.3A2 combustion turbine at our Riverton Plant, which is scheduled to be operational in 2007.
A detailed discussion on cash flow activity follows.
Cash Provided by Operating Activities
Our net cash flows provided by operating activities decreased $0.5 million during 2006 as compared to 2005. Cash flows were positively impacted mainly by a $15.5 million increase in net income and a $14.3 million cash flow change in accounts receivable and accrued unbilled revenues. There was also no pension contribution in 2006 as compared to an $11.5 million pension contribution in 2005. These positive impacts were offset mainly by a $30.0 million cash flow change in accounts payable and accrued liabilities and a $6.3 million cash flow change in fuel, materials and supplies. Changes in adjustments to net income for non-cash items were $5.2 million less in 2006 compared to 2005 mainly due to decreases in deferred income taxes.
Our net cash flows provided by operating activities increased $0.5 million during 2005 as compared to 2004. This reflects, in part, a $1.9 million increase in net income, which includes a $5 million one-time gain in the third quarter of 2005 resulting from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period. Changes in adjustments to net income for non-cash items were $3.5 million more during 2005 versus 2004 primarily due to increases in depreciation and amortization and pension costs. A $5.0 million decrease due to increased working capital requirements, primarily due to a decrease in accounts receivable and accrued unbilled revenue, and an $11.5 million pension contribution in the fourth quarter of 2005, negatively impacted cash flows.
Prior to year end 2005, our accumulated pension benefit obligation (ABO) was projected to be higher than the fair value of our plan assets at December 31, 2005. Therefore, we elected to make an additional cash contribution of $11.5 million to our pension plan in 2005. This cash contribution had no effect on net income. See Note 9 of “Notes to Consolidated Financial Statements” under Item 8 for further discussion regarding our pension and post-retirement benefit plans.
Capital Requirements and Investing Activities
Our net cash flows used in investing activities increased $148.7 million during 2006 as compared to 2005, primarily reflecting our acquisition of Missouri Gas, additions to our transmission and distribution systems and construction expenditures for Plum Point Unit 1, Iatan 2 and the new combustion turbine at our Riverton Plant.
Our net cash flows used in investing activities increased $32.0 million during 2005 as compared to 2004, primarily reflecting additions to our transmission and distribution systems and construction expenditures for the new combustion turbine at our Riverton Plant.
Our capital expenditures for continuing operations totaled approximately $120.2 million (excluding the acquisition of Missouri Gas), $73.4 million, and $41.3 million in 2006, 2005 and 2004, respectively. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.
A breakdown of these capital expenditures for 2006, 2005 and 2004 is as follows:
Approximately 30%, 56% and 99% of our cash requirements for capital expenditures for 2006 (excluding the acquisition of Missouri Gas), 2005 and 2004, respectively, were satisfied with internally generated funds (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.
We estimate that our capital expenditures will total approximately $171.0 million in 2007, $203.9 million in 2008 and $147.3 million in 2009 (including AFUDC). Of these budgeted amounts, we anticipate that we will spend the following amounts over the next three years for the following projects:
* Does not include costs associated with the January 2007 ice storm.
Testing on the new Riverton unit began on January 12, 2007. Construction on the Energy Station began in the spring of 2006 with completion scheduled for 2010. Initially we will own, through an undivided interest, 50 megawatts of the project’s capacity. 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. See Note 12 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding commitments.
Iatan 2 and Plum Point Unit 1 are important components of a long-term, least-cost resource plan to add approximately 200 megawatts of 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.
We are installing pollution control equipment at the Iatan Plant by 2008 which will include a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a baghouse, with our share of the capital cost estimated at $49 million (including AFUDC). We incurred approximately $3.9 million of this cost in 2006. We are constructing an SCR at Asbury which we expect to be in service around January 2008. Our current cost estimate for an SCR at Asbury is $30 million. For additional information, see Item 1, “Business - Environmental Matters.”
We estimate that internally generated funds will provide approximately 37% of the funds required in 2007 for our budgeted capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to finance additional amounts needed beyond those provided by operating activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements. The estimates herein may be changed because of changes we make in our construction program, unforeseen construction costs, our ability to obtain financing, regulation and for other reasons.
Financing Activities
Our net cash flows provided in financing activities increased $141.4 million to a provision of $143.7 million during 2006 as compared to a provision of $2.2 million in 2005, primarily due to increased proceeds from the issuance of common stock and EDG first mortgage bonds in 2006.
Our net cash flows provided in financing activities increased $35.4 million to a provision of $2.2 million during 2005 as compared to a use of $33.1 million in 2004, primarily due to increased borrowing of short-term debt (commercial paper).
On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.3 million. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.
On June 1, 2006, we used $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG to fund a portion of our acquisition of Missouri Gas from Aquila, Inc. We used short-term debt to fund the remainder of the acquisition, which was replaced with common equity on June 21, 2006.
On June 21, 2006, we sold 3,795,000 shares of our common stock, including an additional 495,000 shares to cover the underwriters’ over-allotments, in an underwritten public offering for $20.25 per share.
The sale resulted in net proceeds of approximately $73.3 million ($76.8 million less issuance costs of $3.5 million). The proceeds were used to pay down short-term debt, including short-term debt used to fund a portion of our acquisition of Missouri Gas.
We have an effective shelf registration statement with the SEC under which approximately $323.2 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance. Of this amount, $200 million has been approved by the MPSC as available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this shelf to fund a portion of the capital expenditures for our new generation projects.
On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point Unit 1 and is $65.0 million as of January 1, 2007. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2006, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at December 31, 2006, however, $77.1 million of the availability thereunder was used at such date to back up our outstanding commercial paper.
Restrictions in the EDE mortgage bond indenture could affect our liquidity. 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 fifteen 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 with 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.
The 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, EDG’s 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.
As of January 31, 2007, our corporate credit ratings and the ratings for our securities were as follows:
On September 22, 2005, Standard & Poor’s (S&P), reflecting our announcement of our proposed acquisition of Aquila, Inc.’s Missouri natural gas properties, placed our corporate credit rating on credit watch with negative implications. S&P stated that the acquisition comes in addition to our embarking on a capital spending program that is significantly higher than historical levels and will be partially debt financed. On February 13, 2006, S&P removed our corporate credit rating from credit watch, but placed us on negative outlook. S&P also reduced the rating on our commercial paper from A-2 to A-3 on February 21, 2006. This reduction made it more difficult for us to issue commercial paper and, as a result, our short-term debt during the period from February 21, 2006 to June 30, 2006, was in the form of borrowings under our revolving credit facility. However, beginning on June 30, 2006, we were able to again issue commercial paper at the current rating under a new agreement with Wells Fargo Bank. On May 17, 2006, S&P lowered our long-term corporate credit rating to BBB- from BBB, senior secured debt to BBB+ from A-, senior unsecured debt rating to BB+ from BBB- and affirmed our short-term rating of A-3. S&P’s downgrade reflected their view that our financial measures will be constrained over the next several years by fuel and power costs that continue to exceed the level recoverable in rates, and by our higher-than-historical level of capital spending, including the acquisition of Missouri Gas.
Moody’s affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable. On January 24, 2007, Moody’s again affirmed our ratings but changed their rating outlook on us back to negative. The change to a negative rating outlook reflects Moody’s view on the longer-term prospects for our ratings given the sizable capital spending program we have committed to through 2010 and the potential for further weakness in our credit metrics that could develop during this time.
In September 2005, we entered into an agreement with Fitch Ratings to initiate coverage of us and to assign ratings to our outstanding debt securities. On December 19, 2005, Fitch Ratings initiated coverage and assigned ratings (see table above) with a stable rating outlook. Fitch announced that their ratings reflect our low business risk position as a regulated electric utility, a stable service territory and a seemingly improving regulatory environment in Missouri where we receive approximately 89% of our electric revenues.
CONTRACTUAL OBLIGATIONS
Set forth below is information summarizing our contractual obligations as of December 31, 2006. Not included in these amounts are expected obligations associated with our share of the Iatan 2 construction and Iatan 1 environmental construction additions for which we have not yet been billed and the installation of the new combustion turbine at Riverton for which purchase orders have not been opened. Other postretirement benefit plans are funded on an ongoing basis to match their corresponding costs, per
regulatory requirements and have been estimated for 2007-2011 as noted below. Future pension funding commitments are not expected to be material over the next 5 years and have not been estimated for later years.
(1) Some of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.
(2) Excludes payments under our Elk River Windfarm agreement, as payments are contingent upon output of the facility. Payments can run from zero up to a maximum of $15.2 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours.
(3) Includes a water usage contract for our SLCC facility, fuel and purchased power contracts and associated transportation costs, as well as purchased power for 2010 through 2015 for Plum Point Unit 1.
(4) Represents fuel contracts and associated transportation costs of our gas segment.
(5) Other long-term liabilities primarily represents electric facilities charges owed to City Utilities of Springfield, Missouri of $11,000 per month over 30 years starting in January 2007.
DIVIDENDS
Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, 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 as of December 31, 2005, after paying out $36.1 million in dividends during 2006. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.
Our diluted earnings per share were $1.39 for the twelve months ended December 31, 2006 and were $0.92 and $0.86 for the years ended December 31, 2005 and 2004, respectively. Dividends paid per share were $1.28 for the twelve months ended December 31, 2006 and for each of the years ended December 31, 2005 and 2004.
In addition, the Mortgage and our 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 earned surplus did not prevent us from paying 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.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.
CRITICAL ACCOUNTING POLICIES
Set forth below are certain accounting policies that are considered by management to be critical and that typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
Pensions and Other Postretirement Benefits (OPEB). We recognize expense related to pension and postretirement benefits as earned during the employee’s period of service. Related assets and liabilities are established based upon the funded status of the plan. Our postretirement expense or benefit includes amortization of previously unrecognized net gains or losses. The amortized amount for postretirement benefits represents the average of the unrecognized net gains and losses as of the prior five measurement dates, with this amount being amortized over five years. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits (effective January 1, 2005), unrecognized net gains or losses as of the measurement date are amortized over ten years.
In our 2005 electric Missouri Rate Case (effective March 27, 2005), the MPSC ruled that we would be allowed to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate order, we will prospectively calculate the value of plan assets using a market related value method (as allowed by SFAS 87). This is a change from the policy approved in the 2002 order, which allowed us to recover pension costs on an ERISA minimum funding (or cash) basis. Prior to the 2002 order, the MPSC allowed us to recover pension costs consistent with our GAAP policy. We had determined that the difference between the ERISA recovery allowed by the MPSC and our accounting for pension costs under GAAP did not meet the FAS 71 requirements for treatment as a regulatory asset or liability. As a result, we have continued to account for pension expense or benefits in accordance with SFAS 87, using the previously mentioned amortization formula for recognizing net gains or losses.
The MPSC ruled this change in the recognition of pension costs would allow us to record the Missouri portion of any costs above or below the amount included in rates as a regulatory asset or recognize a regulatory liability for costs incurred that are less than those allowed in rates. Therefore, the deferral of
these costs began in the second quarter of 2005. In our agreement with the MPSC regarding the purchase of Missouri Gas by EDG, we were allowed to adopt this pension cost recovery methodology for EDG, as well. Also, it was agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be ignored for ratemaking purposes. These acquisition entries have been recorded as regulatory assets, as these amounts will be recovered in future rates. The regulatory asset will be reduced by an amount equal to the difference between the regulatory costs and the estimated FAS 87 costs. The difference between this total and the costs being recovered from customers will be deferred as a regulatory asset or liability. In our most recently approved Kansas Rate Case (effective January 1, 2006), the KCC also ruled that we would be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in our rate case as a regulatory asset or liability. We now expect future pension expense or benefits will be fully recovered or recognized in rates charged to our Missouri and Kansas customers, thus lowering our sensitivity to risks and uncertainties.
Our 2006 Missouri rate case order allows us to defer any OPEB that is 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 includes the use of a market-related value of assets, the amortization of unrecognized gains or losses over ten years and the recognition of regulatory assets and liabilities in the immediately preceding paragraph. Factors that could result in additional postretirement expense include: a lower discount rate than estimated, higher compensation rate and medical cost rate increases, lower return on plan assets, and longer retirement periods.
On September 29, 2006, the FASB issued FASB No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (FAS 158). FAS 158 is intended to improve financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. FAS 158 is effective for us for the fiscal year ended December 31, 2006. Based on the regulatory treatment of pension and OPEB recovery afforded in our jurisdictions, we have concluded that the amount of unfunded defined benefit pension and postretirement plan obligations will be recorded as regulatory assets on our balance sheet rather than as reductions of equity through comprehensive income.
Risks and uncertainties affecting the application of our pension accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), demographic assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. Factors that could result in additional pension expense include: a lower discount rate than estimated, higher compensation rate increases, lower return on plan assets, and longer retirement periods.
Risks and uncertainties affecting the application of our OPEB accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates).
Hedging Activities. We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results. All derivative instruments are recognized on the balance sheet with gains and losses from effective instruments deferred
in other comprehensive income (in stockholders’ equity), while gains and losses from ineffective (overhedged) instruments are recognized as the fair value of the derivative instrument changes.
As of February 16, 2007, approximately 82% of our anticipated volume of natural gas usage for our electric segment operations for the remainder of the year 2007 is hedged (either through financial derivative contracts or physical forward purchase agreements which include any physical gas in storage) at an average price of $6.292 per Dekatherm (Dth). In addition, the following percentages and amounts of our anticipated volume of natural gas usage for our electric segment operations for the next six years (representing our financial and physical hedges) are hedged at the following average prices per Dth:
Risks and uncertainties affecting the application of this accounting policy include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately in our Consolidated Statement of Income.
We hedge a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of February 14, 2007, we have 0.8 million Dths hedged, which represents 98% of our expected usage for our gas operations for the remainder of the winter season (through March 2007). Our long-term hedge strategy for our gas segment is still in the development process. A PGA clause is included in our rates, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.
Regulatory Assets and Liabilities. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over us (FERC and four states).
Certain expenses and credits, normally recognized as incurred, are deferred as assets and liabilities on the balance sheet until the time they are recovered from or refunded to customers. We have recorded certain regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature which are determined by our regulators to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures, and we believe that the regulatory assets and liabilities we have recorded will be afforded similar treatment. If these items are not afforded similar treatment they will be required to be recognized in our statement of income.
As of December 31, 2006, we have recorded $94.4 million in regulatory assets and $49.8 million in income taxes, gain on interest rate derivatives and costs of removal as regulatory liabilities. See Note 4 of “Notes to Consolidated Financial Statements” under Item 8 for detailed information regarding our regulatory assets and liabilities.
We continually assess the recoverability of our regulatory assets. Under current accounting standards, regulatory assets and liabilities are eliminated through a charge or credit, respectively, to earnings if and when it is no longer probable that such amounts will be recovered through future revenues.
Risks and uncertainties affecting the application of this accounting policy include: regulatory environment, external regulatory decisions and requirements, anticipated future regulatory decisions and their impact and the impact of deregulation and competition on ratemaking process and the ability to recover costs.
Unbilled Revenue. At the end of each period we estimate, based on expected usage, the amount of revenue to record for energy and natural gas that has been provided to customers but not billed. Risks and uncertainties affecting the application of this accounting policy include: projecting customer energy usage, estimating the impact of weather and other factors that affect usage (such as line losses) for the unbilled period and estimating loss of energy during transmission and delivery.
Contingent Liabilities. We are a party to various claims and legal proceedings arising in the ordinary course of our business. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our evaluation as of the end of 2006, we believe that we have accrued liabilities in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5) sufficient to meet potential liabilities that could result from these claims. This liability at December 31, 2006 and 2005 was $1.6 million and $1.5 million, respectively.
Risks and uncertainties affecting these assumptions include: changes in estimates on potential outcomes of litigation and potential litigation yet unidentified in which we might be named as a defendant.
Goodwill. We recorded goodwill upon the completion of the Missouri Gas acquisition of $39.3 million. Goodwill represents the excess of the cost of the acquisition over the fair value of the related net assets at the date of acquisition. In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Circumstances under which impairment could occur include not realizing anticipated synergies, adverse regulatory treatment or the loss of gas customers. In performing impairment tests, valuation techniques require the use of estimates with regard to discounted future cash flows of operations, involving judgments based on a broad range of information and historical results. If the test indicates impairment has occurred, goodwill would be reduced, adversely impacting earnings. We performed our annual goodwill impairment test as of October 31, 2006 and concluded our goodwill was not impaired.
Risks and uncertainties affecting these assumptions include: management’s identification of impairment indicators, changes in business, industry, laws technology or economic and market conditions, and valuation assumptions and conclusion.
Use of Management’s Estimates. The preparation of our consolidated financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to unbilled utility revenues, collectibility of accounts receivable, depreciable lives, asset impairment and goodwill evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation and tax provisions. Actual amounts could differ from those estimates.
RECENTLY ISSUED ACCOUNTING STANDARDS
See Recently Issued and Proposed Accounting Standards under Note 1 of “Notes to Consolidated Financial Statements” under Item 8.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle our commodity market risk in accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions. We utilize derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 15 of “Notes to Consolidated Financial Statements” under Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
of the Empire District Electric Company:
We have completed integrated audits of The Empire District Electric Company’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries (the Company) at December 31, 2006 and 2005 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for pension and other post-retirement benefits on December 31, 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management’s Report on Internal Controls Over Financial Reporting, management has excluded The Empire District Gas Company from its assessment of internal control over financial reporting as of December 31, 2006 because it was acquired by the Company in a purchase business combination during 2006. We have also excluded The Empire District Gas Company from our audit of internal control over financial reporting. The Empire District Gas Company is a wholly-owned subsidiary whose total assets and total revenues represent 9.5 percent and 6.1 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2006.
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2007
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS (Continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Consolidated Statements of Income
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
General
We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. It provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment includes investments in certain non-regulated businesses including fiber optics and Internet access. These businesses are held by our wholly-owned subsidiary, EDE Holdings, Inc (EDE Holdings). For discussion of the activities of our other operating segment, see Note 13. 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 sales from our gas segment and 0.9% from our other segment.
The utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities.
Our electric 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 retail electric revenues for 2006 by jurisdiction were as follows: Missouri 87.6%, Kansas 6.1%, Arkansas 3.3%, and Oklahoma 3.0%.
Our gas operations serve approximately 47,200 customers and the 2006 gas operating revenues were derived as follows: residential 67.6%, commercial 30.2%, industrial 1.5% and other 0.7%.
Following is a description of the Company’s significant accounting policies:
Basis of Presentation
The consolidated financial statements include the accounts of EDE, EDG, and EDE Holdings and its subsidiaries. The consolidated entity is referred to throughout as “we” or the “Company”. Significant intercompany balances and transactions have been eliminated in consolidation. See Note 13 for additional information regarding our three segments.
Discontinued Operations
In August and December 2006, we sold two of our other businesses, our controlling 52% interest in Mid-America Precision Products (MAPP) and our 100% interest in Conversant, respectively. MAPP specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries, which was sold to other current owners. We owned 100% of Conversant, a software company that markets Customer Watch, an internet-based customer information system software. We have reclassified the results of their operations to discontinued operations.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Accounting for the Effects of Regulation
In accordance with Statement of Financial Accounting Standards SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC).
In accordance with FAS 71, certain expenses and credits, normally recognized as incurred, are deferred as assets and liabilities on the balance sheet until the time they are recognized when recovered from or refunded to customers. As such, we have recorded certain regulatory assets and liabilities which are expected to result in future increased or decreased revenues respectively, as these costs are recovered through the ratemaking process.
These include the effects of a purchased gas adjustment (PGA) clause related to our gas segment. This PGA clause allows us to recover our actual cost of natural gas from customers through rate changes. It allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions, gas prices 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 regulatory asset or regulatory liability until the balance is recovered from or credited to customers.
Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. We continually assess the recoverability of our regulatory assets. Regulatory assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues.
Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in FAS 71 with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of FAS 71 based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 4 for further discussion of regulatory treatment).
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectibility of accounts receivable, depreciable lives, asset impairment and goodwill evaluations,
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation and tax provisions. Actual amounts could differ from those estimates.
Revenue Recognition
For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. We also accrue a liability for the related taxes at the end of each period. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The unbilled estimates are determined based on various assumptions, such as current month electric load requirements, billing rates by customer classification and line loss factors. Changes in those assumptions can significantly affect the estimates of unbilled revenues. During 2006, the Company recorded a $5.9 million increase in electric unbilled revenues as a result of certain changes to the assumptions used in determining estimated unbilled revenues.
Through December 31, 2006 we collected an Interim Energy Charge (IEC) of $0.002131 per kilowatt hour of customer usage authorized by the MPSC. The IEC was designed to recover variable fuel and purchased power costs we incurred subject to a ceiling and floor on the amount recoverable (including realized gains or losses associated with our natural gas hedging program) which are higher than such costs included in the base rates allowed in the 2005 Missouri rate case. This revenue was recorded when service was provided to the customer and subject to refund to the extent collected amounts exceeded variable fuel and purchased power costs. At each balance sheet date, we evaluated the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to ratepayers. At December 31, 2006, no provision for refund has been recorded. Effective January 1, 2007 the IEC was eliminated. This elimination is a result of an order issued by the MPSC on December 22, 2006. (See Note 4 for additional discussion)
Property, Plant & Equipment
The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material and an allocation of general and administrative costs, plus an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of is charged to accumulated depreciation. Maintenance expenditures and the removal of items not considered units of property are charged to income as incurred.
Until 2002, the depreciation/cost of service methodology utilized by our rate-regulated operations included an estimated cost of dismantling and removing plant from service upon retirement. From January 2002 through March 2005, we suspended accruing the cost of removing plant from service upon retirement through depreciation rates pursuant to the October 2001 Missouri rate case. Pursuant to our Missouri rate case, effective March 27, 2005, we began accruing cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets) on April 1, 2005. We reclassified the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under SFAS 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143), from accumulated depreciation to a regulatory liability. At December 31, 2006, and 2005, the amount of accrued cost of removal was $27.4 million and $21.3 million, respectively, for our electric operating segment. We have a similar cost of removal regulatory liability for our gas operating segment of $4.0 million at December 31, 2006. These amounts are net of our actual cost of removal expenditures.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Depreciation
Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other businesses are computed at straight-line rates over the estimated useful life of the properties.
The table below summarizes the total provision for depreciation and depreciation rates for continuing operations, both capitalized and expensed for the years ended December 31:
The table below sets forth the average depreciation rate for each class of assets, which have been consistently applied for all periods presented:
Allowance for Funds Used During Construction
As provided in the regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to our construction program are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.
AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.
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Notes to Consolidated Financial Statements (Continued)
In accordance with the methodology prescribed by FERC, we utilized aggregate rates (on a before-tax basis) of 7.2% for 2006, 7.6% for 2005 and 6.9% for 2004, compounded semiannually, in determining AFUDC for all of our projects except Iatan 2. The specific Iatan 2 AFUDC rate is a result of our Experimental Regulatory Plan approved by the MPSC on August 2, 2005. In this agreement we were allowed to receive regulatory amortization in rates prior to the completion of Iatan 2. As a result the equity portion of our AFUDC rate for the Iatan 2 project was reduced by 2.5 percentage points. (See Note 4 for additional discussions of our regulatory plan.)
Asset Impairments
We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on several criteria, including but not limited to revenue trends, undiscounted forecasted cash flows and other operating factors, to determine the impairment amount.
Goodwill
We recorded goodwill upon the completion of the Missouri Gas acquisition of $39.3 million. Goodwill represents the excess of the cost of the acquisition over the fair value of the related net assets at the date of acquisition. In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Circumstances under which impairment could occur include not realizing anticipated synergies, adverse regulatory treatment or the loss of gas customers. In performing impairment tests, valuation techniques require the use of estimates with regard to discounted future cash flows of operations, involving judgments based on a broad range of information and historical results. If the test indicates impairment has occurred, goodwill would be reduced, adversely impacting earnings. We performed our annual goodwill impairment test as of October 31, 2006 and concluded our goodwill was not impaired.
Derivatives
Electric Segment
Pursuant to FASB 133, Accounting for Derivative Instruments and Hedging Activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (“cash-flow” hedge); or (2) an instrument that is held for non-hedging purposes (a “non-hedging” instrument). Changes in the fair value of a derivative that is highly effective and designated and qualifies as a cash-flow hedge are recorded in other comprehensive income until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable-rate asset or liability are recorded in earnings). Changes in the fair value of non-hedged derivative instruments and any ineffective portion of a qualified hedge are reported in current-period earnings in fuel expense.
We discontinue hedge accounting prospectively when (1) it is determined that the derivative is no longer highly effective in offsetting changes in cash flows of a hedged item (including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; (3) the derivative is de-designated as a non-hedging instrument, because it is less than probable that a forecasted transaction will
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Notes to Consolidated Financial Statements (Continued)
occur; or (4) management determines that designation of the derivative as a hedge instrument is no longer appropriate. (See Note 15)
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions.
Gas Segment
Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense and then is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year.
This is consistent with FAS 71, in that we will be recovering our costs after the annual true up period (subject to prudency review by the MPSC).
Pension and Other Postretirement Benefits
We recognize expense related to pension and other postretirement benefits as earned during the employee’s period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our expense calculation includes amortization of previously unrecognized net gains or losses. The amortized amount for postretirement benefits represents the average of the unrecognized net gains and losses as of the prior five measurement dates with this amount being amortized over five years. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits (effective January 1, 2005), unrecognized net gains or losses as of the measurement date are amortized over ten years.
Pensions In our 2005 electric Missouri Rate Case (effective March 27, 2005), the MPSC ruled the Company would be allowed to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate order, we prospectively calculated the value of plan assets using a market-related value method (as allowed by SFAS 87). This is a change from the policy approved in the 2002 order, effective December 1, 2002, which allowed us to recover pension costs on an ERISA minimum funding (or cash) basis. Prior to the 2002 order, the MPSC allowed the Company to recover pension costs consistent with our GAAP policy. We had determined that the difference between the ERISA recovery allowed by the MPSC and our accounting for pension costs under GAAP did not meet the FAS 71 requirements for treatment as a regulatory asset or liability. As a result, the Company has continued to account for pension expense or benefits in accordance with SFAS 87, using the previously mentioned amortization formula for recognizing net gains or losses.
The MPSC ruled the 2005 change in the recognition of pension costs would allow the Company to record the Missouri portion of any costs above the amount included in the 2005 rate case as a regulatory asset or recognize a regulatory liability for costs incurred that are less than those allowed in rates. Therefore, the deferral of these costs began in the second quarter of 2005. In the order approved April 18, 2006 by the MPSC regarding the purchase of Missouri Gas by EDG, the Company was allowed to adopt
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Notes to Consolidated Financial Statements (Continued)
this pension cost recovery methodology for EDG as well. Also, it was agreed that the effects of purchase accounting entries related to pension and other postretirement benefits would be ignored for ratemaking purposes. These acquisition entries have been recorded as regulatory assets, as these amounts will be recovered in future rates. The regulatory asset will be reduced by an amount equal to the difference between the regulatory costs and the estimated FAS 87 costs. The difference between this total and the costs being recovered from customers will be deferred as a regulatory asset or liability. In the most recently approved Kansas Rate Case (effective January 1, 2006), the KCC also ruled that the Company would be allowed to change the recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in the rate case as a regulatory asset or liability. The Company now expects future pension expense or benefits will be fully recovered or recognized in rates charged to Missouri and Kansas customers, thus lowering sensitivity to risks and uncertainties.
Other Postretirement Benefits (OPEB) In our most recent Missouri rate case, effective January 1, 2007, the MPSC approved regulatory treatment for our OPEB costs similar to the treatment described above for our pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses over ten years and the recognition of regulatory assets and liabilities in the immediately preceding paragraph.
In the third quarter of 2004, we adopted FASB staff position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”. Beginning December 31, 2004, accumulated postretirement benefit obligation (APBO) and net cost recognized for OPEB reflects the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act provides for a federal subsidy, beginning in 2006, of 28% of prescription drug costs between $250 and $5,000 for each Medicare-eligible retiree who does not join Medicare Part D, to companies whose plans provide prescription drug benefits to their retirees that are “actuarially equivalent” to the prescription drug benefits provided under Medicare. Equivalency must be certified annually by the Federal Government. Our plan provides prescription drug benefits that are “actuarially equivalent” to the prescription drug benefits provided under Medicare and have been certified as such.
On September 29, 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (FAS 158). FAS 158 is intended to improve financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. FAS 158 is also intended to improve financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. FAS 158 was effective for us for the fiscal year ended December 31, 2006, and we adopted FAS 158 as of that date. Based on the regulatory treatment of pension and OPEB recovery afforded in the Company’s jurisdictions, the Company has concluded that the amount of unfunded defined benefit pension and postretirement plan obligations will be recorded as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income. (See Note 9).
We utilized the assistance of our plan actuaries in determining the discount rate assumption used in our December 31, 2006 plan obligation estimates. Our actuaries have developed an interest rate yield curve to enable companies to make judgments pursuant to Emerging Issues Task Force EITF Topic
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Notes to Consolidated Financial Statements (Continued)
No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of Post Retirement Benefit Plans Other Than Pensions.” The yield curve is constructed based on the yields on over 500 high-quality, non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of our pension plan and develop a single-point discount rate matching the plan’s payout structure.
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.
Liability Insurance
We carry excess liability insurance for workers’ compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and workers compensation claims are covered by a guaranteed cost policy. (See Note 12)
Franchise Taxes
Franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Franchise taxes of $7.3 million, $6.4 million and $5.4 million were recorded for each of the years ended December 31, 2006, 2005 and 2004, respectively.
Cash & Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities. At December 31, 2006 and 2005, these amounts were $12.7 million and $11.8 million, respectively.
Fuel, Material and Supplies
Fuel, material and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are as follows (in thousands):
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Notes to Consolidated Financial Statements (Continued)
Income Taxes
Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates. (See Note 10).
Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. Remaining unamortized investment tax credits are being amortized over remaining lives of approximately 24 years.
Computations of Earnings Per Share
Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding under the assumed exercise of dilutive restricted shares and options. The weighted average number of common shares outstanding used to compute basic earnings per share for the 2006, 2005, and 2004 periods were 28,276,568, 25,898,428 and 25,467,740, respectively. Additional dilutive shares for the 2006, 2005, and 2004 periods were 19,827, 42,680, and 53,223, respectively. Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company’s stock price occurs. Antidilutive shares for 2006, 2005 and 2004 were 48,903, 41,115 and 57,384, respectively.
Stock-Based Compensation
At December 31, 2006, we had several stock-based compensation plans, which are described in more detail in Note 5. During 2002, we adopted SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of SFAS 123” (FAS 148), and elected to adopt the accounting provision of FAS 123 “Accounting for Stock-Based Compensation” (FAS 123). Under FAS 123, we recognized compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. We adopted FAS 123(R) on January 1, 2006 using the modified prospective approach. See Note 5 - “Common Stock.” The adoption of FAS 123(R) did not have a material impact on our stock compensation expense.
Asset Retirement Obligations
We account and report for legal obligations associated with the retirement or anticipated retirement of tangible long-lived assets in accordance with SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.
We have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We
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Notes to Consolidated Financial Statements (Continued)
also have a liability for future containment of an ash landfill at the Riverton Power Plant along with a liability for future asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date.
All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. The balances at the end of 2005 and 2006 are shown below.
Upon adoption of these standards, we recorded a non-recurring discounted liability and a regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses.
Also as noted previously under depreciation, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset retirement obligation under FAS 143, from accumulated depreciation to a regulatory liability. This balance sheet reclassification had no impact on results of operations.
Recently Issued and Proposed Accounting Standards
On July 13, 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” (FIN 48) which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for the Company as of January 1, 2007. We are completing our evaluation of the impact of adopting FIN 48, and do not expect it to have a material impact on our results of operations.
On September 15, 2006, the FASB issued FASB No. 157, “Fair Value Measurements” (FAS 157), which provides guidance for using fair value to measure assets and liabilities. FAS 157 also responds to investors’ requests for more information about (1) the extent to which companies measure assets and liabilities at fair value, (2) the information used to measure fair value and (3) the effect that fair-value measurements have on earnings. FAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any new circumstances. FAS 157 is effective for financial statements issued for fiscal years beginning after
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Notes to Consolidated Financial Statements (Continued)
November 15, 2007 and interim periods within those fiscal years. We do not expect the pronouncement to have a material effect on our financial statements.
2. Acquisition of Missouri Natural Gas Distribution Operations
On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. This acquisition was completed by EDG on June 1, 2006. We expect this acquisition to help diversify our weather risk, balancing our current summer air conditioning peak with a natural gas winter heating peak. The base purchase price for these properties 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. The total purchase price, including working capital and net plant adjustments but excluding acquisition costs, was $102.5 million. We recorded $39.3 million of goodwill as a result of the acquisition. All of this is expected to be tax deductible.
The components of the purchase price allocation for the Missouri Gas acquisition are shown below. (See Note 7 - “Long-Term Debt,” for the information on the purchase price financing). Assets and liabilities are valued at fair value. In the case of property, plant and equipment, fair value is calculated in a manner consistent with the amount recoverable for regulatory treatment.
The following presents certain proforma financial information for the year ended December 31, 2006, 2005 and 2004, as if our acquisition of Missouri Gas had been completed as of the beginning of 2004. These estimates are based on historical results of the Missouri Gas operations, provided to us by Aquila, Inc., and are unaudited. In addition, they do not include the effects of any financing costs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Property, Plant and Equipment
Our total property, plant and equipment is summarized below.
(1) Includes intangible property of $9.9 million as of December 31, 2006, primarily related to capitalized software. Accumulated amortization related to this property in 2006 was $6.1 million. This is primarily capitalized software.
4. Regulatory Matters
Rate Matters
We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Electric Segment
The following table sets forth information regarding electric and water rate increases since January 1, 2004:
Missouri
On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. On December 22, 2004, we, the MPSC Staff, the Office of the Public Counsel (OPC) and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above or below the amount included in this rate case as a regulatory asset or liability. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.
The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates included a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC was $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, an assessment would be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts was greater than $10 million, the excess over $10 million would be refunded to the customers. The entire excess amount of IEC, not previously refunded, would be refunded at the end of three years, unless the IEC was terminated earlier. Each refund was to include interest at the current prime rate at the time of the refund. The IEC revenues recorded since the inception of the IEC did not recover all the Missouri related fuel and purchased power costs incurred during that period. From inception of the IEC through December 31, 2006, the costs of fuel and purchased power were approximately $22.3 million higher than the total of the costs in our base rates and the IEC recorded during the period, therefore, no provision for refund was recorded.
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 also requested transition from the IEC to Missouri’s new fuel adjustment mechanism. The MPSC issued an order May 2, 2006, however, ruling that we may have the option of requesting that the IEC be terminated, but we may not request the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
implementation of an energy cost recovery mechanism while the current IEC is effective. 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 this order, the collected IEC will not be refunded. The increase included an authorized return on equity of 10.9% and included our 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. This regulatory amortization is related to our investment in Iatan 2 and also includes our Riverton V84.3A2 combustion turbine (Unit 12) and the environmental improvements and upgrades at Asbury and Iatan 1. This order also allowed deferral of any OPEB that is different from those allowed recovery in this 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 FAS 158. (See Note 1 for additional information).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 MPSC’s 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 OPC’s Petition is still pending.
On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.
Arkansas
On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005.
Kansas
On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our 2005 Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in this rate case as a regulatory asset or liability. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006. We made this filing on March 30, 2006 and are awaiting a response from the KCC.
Gas Segment
On June 1, 2006, EDG acquired the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of 44 Missouri communities in northwest, north central and west central Missouri. The rates, excluding the cost of gas, are the same as had been in effect at Aquila, Inc. We agreed in the unanimous stipulation and agreement filed with the MPSC on March 1, 2006 and approved on April 18, 2006, to not file a rate increase request for non-gas costs for a period of 36 months following the closing date of the acquisition. We have also agreed to use Aquila Inc.’s current depreciation rates and were allowed to adopt the pension cost recovery methodology approved in our electric Missouri Rate Case effective March 27, 2005.
A PGA clause is included in our gas rates which allows for the over recovery or under recovery of actual gas costs compared to the cost of gas in the PGA rate. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions, natural gas prices and supply demands, rather than in one possibly extreme change per year. The ACA is a scheduled yearly filing with the MPSC filed between October 15 and November 4 each year. This filing establishes the amount to be recovered from customers for the over/under recovered yearly amounts. A PGA is included in the ACA filing. An optional PGA filing without the ACA can be filed up to three times each year, provided a filing does not occur within 60 days of a previous filing. Our ACA filing was completed on November 3, 2006.
Competition
Electric Segment
SPP-RTO
In 2003, 2004 and 2005, we filed notices of intent with the Southwest Power Pool Regional Transmission Organization (SPP RTO) for the right to withdraw from the SPP RTO effective November of the succeeding year. These notices were given primarily because of uncertainty surrounding the treatment from the states regarding RTO participation and cost recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind these notices, which we have done as recently as October 31, 2006. Because we have now obtained regulatory authorizations from Missouri, Kansas and Arkansas for continued participation in and transfer of functional control of our transmission facilities to the SPP RTO, coupled with the fact that a twelve month withdrawal notice can be submitted to the SPP RTO at any time, we have not filed a notice of intent to withdraw at this time.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On June 13, 2006, the MPSC issued an order approving the Stipulation and Agreement regarding our continued participation in and transfer of functional control of certain transmission facilities to the SPP RTO. Due to needed clarifications regarding the MPSC order, the parties to the agreement, except for the OPC, filed a Motion to Clarify. The Motion to Clarify was granted, and an Amended Order approving the Stipulation and Agreement was issued by the MPSC on July 13, 2006 with an effective date of July 23, 2006. As a condition of the MPSC approval of the Stipulation and Agreement, a Transmission Service Agreement (TSA) between us and the SPP RTO was to be filed and accepted by the FERC. Such filing was made to the FERC on July 31, 2006. During the FERC staff’s review of the filing, it was determined that a revision to our 2002 network integration transmission service agreement and network operating agreement with SPP RTO was necessary to reflect the existence of the TSA. On November 22, 2006, the SPP RTO made a filing of the revised agreements. On January 16, 2007, FERC issued a letter order accepting the revised network and operating agreements and the TSA as approved by the MPSC.
On July 14, 2006, we jointly filed an uncontested Stipulation and Agreement between ourselves, the other Kansas transmission owning utilities, interveners, and the KCC staff regarding a similar authorization to continue participation in the SPP RTO and transfer functional control of our transmission facilities. An order from the KCC approving the Stipulation and Agreement (i.e. our continued participation in the SPP RTO and transfer of functional control of certain transmission facilities) was issued on September 19, 2006.
On November 4, 2005, we filed a request for authorization from the Arkansas Public Service Commission (APSC) for the continued participation in the SPP RTO and transfer of functional control of certain transmission facilities. This filing was later combined with similar filings of Oklahoma Gas and Electric and American Electric Power - Southwestern Electric Power Company as well as the filing for the Certificate of Public Convenience and Necessity of the SPP RTO. On August 10, 2006, the APSC approved the consolidated filing, including ours, with certain reporting conditions.
FERC’s order regarding the MPSC TSA completes our efforts of obtaining the necessary state and federal regulatory approvals to transfer functional control of certain transmission facilities to the SPP RTO and continue our participation in the SPP RTO.
FERC Order No. 2000 requires RTOs to provide real-time energy imbalance services and a market-based mechanism for congestion management. The start of the SPP RTO energy imbalance services market (EIS) was delayed several times in 2006 due to the lack of SPP and market participant readiness. The SPP RTO recently finalized its initial market rules and readiness for implementation and certified its readiness to FERC on December 22, 2006. Additional EIS related filings at the FERC were made by the SPP RTO. On February 1, 2007, the SPP RTO launched its EIS market. 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.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
FERC Market Power Order
In April and July 2004, FERC issued orders regarding new testing standards for assessing market power by entities that have wholesale market-based rate tariffs filed with the FERC. The parameters included in the tests are such that most investor owned electric utilities fail the test within their own control area and are subject to a rebuttable presumption of market power. Entities with wholesale market based rates tariffs are subject to a triennial filing to test for market power and are required to apply the new testing criteria. FERC determination of market power would result in the inability for a utility to continue to charge such market-based rates. In September 2004, we submitted amended and updated market power analyses filings.
On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control area based on our failure to meet one of FERC’s wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC issued its order accepting Empire’s proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders issued since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff applies only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, which could amount to approximately $0.6 million (excluding interest) covering over a thousand hourly energy sales over the past 18 months to numerous counterparties external to our system. In response to the order, we filed a Motion For Extension of time and expedited treatment regarding the refund and requested that such refund be delayed until 15 days after the FERC’s order on our rehearing request. On September 5, 2006, the FERC granted the Motion For Extension, as requested.
On September 14, 2006, we filed a Request For Rehearing of FERC’s August 15 order regarding the refund and market power mitigation we had proposed. We requested a rehearing and a waiver of the refund requirement in its entirety. At this time, we cannot predict the outcome of these proceedings.
Approximately 4.6% of our electric operating revenues in both 2006 and 2005 were derived from sales to on-system wholesale customers, the type of customer for which the FERC is already requiring wheeling, or the use, for a fee, of transmission facilities owned by one company or system to move electrical power for another company or system. Our two largest on-system wholesale customers accounted for 92% of our wholesale business in 2006. We have contracts with these customers through the first quarter of 2008.
Gas Segment
Non residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.
Other - Rate Matters
In accordance with FAS No. 71, we currently have deferred approximately $1.3 million of expense related to rate cases under other non-current assets and deferred charges of which $0.5 million is directly
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
related to the Missouri rate case that was completed in the first quarter of 2005 and $0.5 for the rate case completed in 2006. We amortize this amount over varying periods upon the completion of the specific case. As of December 31, 2006, $0.2 million in expense related to the 2006 Kansas case completed is unamortized. Based on past history, we expect all these expenses to be recovered in rates.
Regulatory Assets and Liabilities and Deferred Items
We have recorded the following regulatory assets and regulatory liabilities. The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss and gain on reacquired debt and the interest rate derivatives are amortized over the life of the new debt issue, which currently ranges from 7 to 29 years.
(1) Includes regulatory assets recorded as a result of the purchase of the Missouri gas assets, the adoption of FAS 158 and other ratemaking effects for pension and OPEB items.
As of December 31, 2006, the costs of all of our regulatory assets are being currently recovered except, for approximately $2.7 million related to unamortized premiums and related costs for debt reacquired, and $32.1 million of pension and postretirement costs primarily related to the additional liabilities for future pension and OPEB costs that were recorded upon adoption of FAS 158. These costs were incurred subsequent to our most recent rate case filings. Since cost recovery of debt costs have historically been allowed in rate cases in all of our jurisdictions we expect them to be approved in future rate case proceedings. (See Note 1 regarding the adoption of FAS 158)
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Common Stock
Recent Issues
On June 21, 2006, we sold 3,795,000 shares of our common stock, including an additional 495,000 shares to cover the underwriters’ over-allotments, in an underwritten public offering for $20.25 per share. The sale resulted in net proceeds of approximately $73.3 million ($76.8 million less issuance costs of $3.5 million). The proceeds were used to pay down short-term debt, including short-term debt used to fund a portion of our acquisition of Missouri Gas.
Stock based compensation
We have several stock-based awards and programs, which are described below. Effective January 1, 2006, we adopted FAS 123(R) “Share-Based Payment” and applied it to our stock-based awards and programs using the modified prospective approach. We had previously recognized compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair value of the award as of the date of issuance. The adoption of FAS 123(R) did not have a material impact on our financial results, as compared to prior periods.
We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in thousands):
Stock Incentive Plans
Our 1996 Incentive Plan (the 1996 Stock Incentive Plan) provided for the grant of up to 650,000 shares of common stock through January 2006. The 1996 Stock Incentive Plan permited grants of stock options and restricted stock to qualified employees and permited Directors to receive common stock in lieu of cash compensation for service as a Director. Our 2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 28, 2005 and provides for grants of up to 650,000 shares of common stock through January 2016. The 2006 Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash compensation for service as a Director. The terms of the 2006 Incentive Plan are substantially the same as the 1996 Stock Incentive Plan. Awards made prior to 2006 were made under the 1996 Stock Incentive Plan. Awards made on or after January 1, 2006 are made under the 2006 Incentive Plan. The terms and conditions of any option or stock grant are determined by the Board of Directors Compensation Committee, within the provisions of these Stock Incentive Plans.
Performance-Based Restricted Stock Awards
Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2004, 2005 and 2006 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and maximum at the 80th percentile level. Shares would be earned at the end of the three-year performance period as follows: 100% of the target number of shares if the target level of performance
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold level is not reached.
For the 2004 and 2005 grants, the fair value of these stock awards was determined based on the number of shares granted and the quoted price of our stock on the date of grant of $21.79 and $22.77, respectively. Upon adoption of FAS123(R), the fair value of the estimated shares awarded under the 2006 grants was estimated on the date of grant using a lattice-based option valuation model with the assumptions noted in the following table:
(1) Three-year average weekly volatility.
(2) The 51.26% represents the estimate of the non-vested awards to be granted.
Non-vested restricted stock awards (based on target number) as of December 31, 2006, 2005 and 2004 and changes during the year ended December 31, 2006, 2005 and 2004 were as follows:
At December 31, 2006, unamortized compensation expense related to estimated outstanding awards was immaterial.
Stock Options
Stock options are issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable after three years and expire ten years after the date granted. Participants’ options that are not vested become forfeited when participants leave Empire except for terminations of employment under certain specified circumstances. Dividend equivalent awards are also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year period until the option becomes exercisable.
The dividend equivalents are accumulated for the three-year period and are converted to shares of our common stock based on the fair market value of the shares on the date converted. To be in compliance
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
with Section 409A of the Internal Revenue Code added by the American Jobs Creation Act of 2004, the dividend equivalent awards (granted in 2004 and 2005) were changed to vest and be payable in fully vested shares of our common stock on the third anniversary of the grant date (conversion date) or at a change in control and not dependent upon the exercise of the related option. This modification did not have a material impact on our financial statements.
A summary of option activity under the plan during the year ended December 31, 2006, 2005 and 2004 is presented below:
The aggregate intrinsic value at December 31, 2006, 2005 and 2004 was approximately $0.3 million, $0.1 million, and $0.4 million, respectively. The intrinsic value of the unexercised options is the difference between the Company’s closing stock price on the last day of the period and the exercise price multiplied by the number of in-the-money options had all option holders exercised their option on the last day of the period.
The weighted-average remaining contractual life of outstanding options at December 31, 2006, 2005 and 2004 was 8.1 years in each year. The outstanding shares as of December 31, 2006 represent the non-vested shares. As of December 31, 2006, there was an immaterial amount of unrecognized compensation expense. The range of exercise prices as of December 31, 2006 was $21.79 - $22.77.
The fair value of the options granted, which is amortized to expense over the option vesting period, has been determined on the date of grant using the methods and assumptions outlined in the table below.
(1) The 2005 and 2004 grants were valued using an Expanded Black-Scholes method, which included a valuation component for the existence of dividend equivalents, rather than a separate assumption for the dividend equivalents issued under Black-Scholes. In 2006, dividend equivalents were separated from the evaluation.
(2) One year historic volatility.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Employee Stock Purchase Plan
Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of December 31, 2006, there were 518,498 shares available for issuance in this plan. The adoption of FAS 123(R) did not change the valuation of the options granted under this plan.
(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2006 to May 31, 2007.
Assumptions for valuation of these shares are shown in the table below.
(1) One-year historic volatility.
Stock Unit Plan for Directors
Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for Directors. This plan enhances our ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provided directors the opportunity to convert previously earned cash retirement benefits to common stock units. All eligible Directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
A total of 400,000 shares are authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend’s record date. We record the related compensation expense at the time we make the accrual for the Directors’ benefits as the Directors provide services. At December 31, 2006, there were 82,680 shares accrued to Directors’ accounts and 359,505 shares available for issuance under this plan.
401(k) Plan and ESOP
Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. We match 50% of each employee’s deferrals by contributing shares of our common stock, such matching contributions not to exceed 3% of the employee’s eligible compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2006, there were 99,655 shares available to be issued.
Dividends
Holders of our common stock are entitled to dividends, if, as and when declared by our Board of Directors out of funds legally available therefore subject to the prior rights of holders of our outstanding cumulative preferred and preference stock. Our indenture of mortgage and deed of trust governing our first mortgage bonds restricts our ability to pay dividends on our common stock. In addition, under certain circumstances (including defaults thereunder), Junior Subordinated Debentures, 8 ½% 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.
6. Preferred and Preference Stock
We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2006 or 2005.
Preference Stock Purchase Rights
Our shareholder rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. Each Right enables the holder to acquire
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
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 one-hundredth share, subject to adjustment. The Rights (other than those held by an acquiring person or group (Acquiring Person)), which expire July 25, 2010, will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. The Rights may be redeemed by us in whole, but not in part, for $0.01 per Right, prior to 10 days after the first public announcement of the acquisition of 10% or more of our common stock by an Acquiring Person. We had 30.2 million and 26.0 million Rights outstanding at December 31, 2006 and 2005, respectively.
In addition, upon the occurrence of a merger or other business combination, or an event of the type referred to in the preceding paragraph, holders of the Rights, other than an Acquiring Person, will be entitled, upon exercise of a Right, to receive either our common stock or common stock of the Acquiring Person having a value equal to two times the exercise price of the Right. Any time after an Acquiring Person acquires 10% or more (but less than 50%) of our outstanding common stock, our Board of Directors may, at their option, exchange part or all of the Rights (other than Rights held by the Acquiring Person) for our common stock on a one-for-one basis.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Long-Term Debt
At December 31, 2006 and 2005, the balance of long-term debt outstanding was as follows:
(1) Represented by our Junior Subordinated Debentures, 8½% Series due 2031. We may redeem some or all of the debentures at any time on or after March 1, 2006, at 100% of their principal amount plus accrued and unpaid interest to the redemption date.
(2) We may redeem some or all of the notes at any time at 100% of their principal amount, plus accrued and unpaid interest to the redemption date.
(3) We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.
On March 1, 2001, Empire District Electric Trust I (Trust) issued 2,000,000 shares of its 8½% Trust Preferred Securities (liquidation amount $25 per preferred security) in a public underwritten offering. Holders of the trust preferred securities are entitled to receive distributions at an annual rate of 8½% of the $25 per share liquidation amount. Quarterly payments of dividends by the trust, as well as payments of principal, are made from cash received from corresponding payments made by us on $50,000,000 aggregate principal amount of 8½% Junior Subordinated Debentures due March 1, 2031, issued by us to the trust and held by the trust as assets. Interest payments on the debentures are tax deductible by us. We have effectively guaranteed the payments due on the outstanding trust preferred securities. The Junior Subordinated Debentures are shown as “Note payable to securitization trust” on our balance sheet.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The principal amount of all series of first mortgage bonds outstanding at any one time is limited by terms of the mortgage to $1 billion. Substantially all of the Company’s property, plant and equipment is subject to the lien of the mortgage. On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.3 million. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.
On June 1, 2006, we used $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG to fund a portion of our acquisition of Missouri Gas from Aquila, Inc. We used short-term debt to fund the remainder of the acquisition, which was replaced with common equity on June 21, 2006.
We have an effective shelf registration statement with the SEC under which approximately $323.2 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance. Of this amount, $200 million has been approved by the MPSC as available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this new shelf to fund a portion of the capital expenditures for our new generation projects.
Restrictions in the EDE mortgage bond indenture could affect our liquidity. 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 fifteen months preceding issuance must be two times the annual interest requirements (as defined in the 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 with 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.
The 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, EDG’s 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 1.0. As of December 31, 2006, this test would not allow us to
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
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.
The carrying amount of our total debt exclusive of capital leases at December 31, 2006 and 2005, approximated its fair market value. These estimates were based on the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of year-end or that will be realizable in the future.
Payments Due by Period (000’s)
8. Short-term Borrowings
At December 31, 2006, commercial paper comprised $77.1 million of short-term debt. Short-term commercial paper outstanding and notes payable averaged $39.6 million and $5.5 million daily during 2006 and 2005, respectively, with the highest month-end balances being $77.1 million and $31.0 million, respectively. The weighted average interest rates during 2006 and 2005 were 5.74% and 3.53% in each period. The weighted average interest rate of borrowings outstanding at December 31, 2006 was 5.69%.
On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility.
On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $65.0 million as of January 1, 2007. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2006, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at December 31, 2006; however, $77.1 million of the availability thereunder was used at such date to back up our outstanding commercial paper.
9. Retirement Benefits
As of December 31, 2006, we adopted FAS 158 and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable that the unfunded amount of these plans will be afforded rate recovery. The tax effect of these entries, including the tax benefit of the Medicare Part D subsidy, are reflected as deferred tax assets and liabilities and regulatory liabilities.
This adoption had the following increase or (decrease) effect on our balance sheet accounts (in millions):
This adoption includes $1.3 million to recognize the impact to our supplemental retirement program (“SERP”) for designated officers of the Company. The total liability recorded for the SERP is $1.9 million. The annual expense in 2006 was $0.3 million and funding from our general fund is expected to be $0.1 million per year for the next 5 years.
Pensions
Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are based on years of service and the employee’s average annual basic earnings. Annual contributions to the plan are at least equal to the minimum funding requirements of ERISA.
We expect there to be no contribution required under ERISA in order to maintain minimum funding levels in 2007. This could change in future years, however, based on actual investment performance, changes in interest rates, any future pension plan funding, reform legislation and finalization of actuarial assumptions.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Our expected benefit payments from our pension trust are as follows (in millions):
The following tables set forth the pension plan’s projected benefit obligation, the fair value of the plan’s assets and its funded status and reflects the effects of the acquisition of the Missouri gas assets from Aquila.
Reconciliation of Projected Benefit Obligations:
Reconciliation of Fair Value of Plan Assets:
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Reconciliation of Funded Status:
(1) Voluntary contribution in 2005 to increase plan asset values and avoid minimum pension liability.
Amounts recognized in the balance sheet as pension obligations consist of:
Amounts recognized in the balance sheet as regulatory assets consist of:
The projected benefit obligation and fair value of plan assets for pension plans with a projected benefit obligation in excess of plan assets at December 31, 2006 and 2005 were as follows:
Projected Benefit Obligation in Excess of Plan Assets:
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Net Periodic Pension Benefit Cost
Net periodic benefit pension cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, for 2006, 2005 and 2004, is comprised of the following components:
Our net periodic pension benefit cost, exclusive of capitalized and deferred amounts, net of tax, as a percentage of net income for 2006, 2005 and 2004 was 6.0%, 10.7%, and 6.8%, respectively.
Estimated amounts to be amortized from regulatory assets in 2007:
Assumptions used to determine Year End Pension Benefit Obligation
Assumptions used to determine Net Periodic Pension Benefit Cost
(1) Net periodic cost for gas segment based on a discount rate of 6.3% as of acquisition date of June 1, 2006.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Allocation of Plan Assets
We utilize fair value in determining the market-related values for the different classes of our pension plan assets.
The Company’s primary investment goals for pension fund assets are based around four basic elements:
1. Preserve capital,
2. Maintain a minimum level of return equal to the actuarial interest rate assumption,
3. Maintain a high degree of flexibility and a low degree of volatility, and
4. Maximize the rate of return while operating within the confines of prudence and safety.
The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund’s principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company’s Investment Committee.
Permissible Investments
Listed below are the investment vehicles specifically permitted:
Equity Oriented
Fixed Income Oriented and Real Estate
·Common Stocks
· Bonds
·Preferred Stocks
· GICs, BICs
·Convertible Preferred Stocks
·Convertible Bonds
· Corporate Bonds (minimum quality rating of Baa or BBB)
·Covered Options
·Hedged Equity of Funds
· Cash-Equivalent Securities (e.g., U.S. T-Bills, Commercial Paper, etc.)
· Certificates of Deposit in institutions with FDIC/FSLIC protection
· Money Market Funds/Bank STIF Funds
· Real Estate - Publicly Traded
The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Those investments prohibited by the Investment Committee without prior approval are:
·Privately Placed Securities
· Warrants
·Commodities Futures
· Short Sales
·Securities of Empire District
· Index Options
·Derivatives
Other Postretirement Benefits
We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.
Our funding policy is to contribute annually an amount at least equal to the revenues collected for the amount of postretirement benefit costs allowed in rates. Based on the performance of the trust assets through December 31, 2006, we expect to be required to fund approximately $4.1 million in 2007.
Our estimated benefit payments from trust assets are as follows (in millions):
The following tables set forth the postretirement plan’s benefit obligation, the fair value of the plan’s assets and its funded status, and reflects the acquisition of the Missouri gas assets.
Reconciliation of Benefit Obligation:
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Reconciliation of Fair Value of Plan Assets:
Reconciliation of Funded Status:
Amounts recognized in the balance sheet consist of:
Amounts recognized in the balance sheet as regulatory assets consist of:
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Net Periodic Postretirement Benefit Cost:
Postretirement benefit cost, a portion of which has been capitalized for 2006, 2005 and 2004, is as follows:
Estimated amounts to be amortized from regulatory assets in 2007:
Assumptions used to determine Year End Post Retirement Benefit Obligation
Assumptions used to determine Net Periodic Post Retirement Benefit Cost
The expected long-term rate of return assumption was based on historical returns and adjusted to estimate the potential range of returns for the current asset allocation.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
The assumed 2006 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 9.0%. Each trend rate decreases 0.50% through 2014 to an ultimate rate of 5.0% in 2014 and subsequent years.
The effect of a 1% increase in each future year’s assumed healthcare cost trend rate on the current service and interest cost components of the net periodic benefit cost is $0.5 million, increasing the cost from $4.4 million to $4.9 million. The effect on the accumulated postretirement benefit obligation is $8.6 million, increasing the obligation from $63.0 million to $71.6 million. The effect of a 1% decrease in each future year’s assumed healthcare cost trend rate for these components is ($0.3) million which would decrease the current service and interest cost from $4.4 million to $4.1 million. The effect on the accumulated benefit obligation is $(6.9) million, decreasing the obligation from $63.0 million to $56.1 million.
Allocation of Plan Assets
We utilize fair value in determining the market-related values for the different classes of our postretirement plan assets.
The Company’s primary investment goals for the component of the fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return.
The Company’s guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company’s Investment Committee.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Permissible Investments:
Listed below are the investment vehicles specifically permitted:
The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.
Those investments prohibited by the Investment Committee are:
·Privately Placed Securities
· Margin Transactions
·Commodities Futures
· Short Sales
·Securities of Empire District
· Index Options
·Derivatives
· Real Estate and Real Property
·Instrumentalities in violation of the Prohibited Transactions Standards of ERISA
· Restricted Stock
10. Income Taxes
Income tax expense components for the years ended December 31 are as follows:
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Deferred Income Taxes
Deferred tax assets and liabilities are reflected on our consolidated balance sheet as follows:
Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows:
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Effective Income Tax Rates
The differences between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were:
11. Commonly Owned Facilities
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. At December 31, 2006 and 2005, our property, plant and equipment accounts included the cost of our ownership interest in the plant of $50.5 million and $49.8 million, respectively, and accumulated depreciation of $36.3 million and $35.4 million, respectively. Expenditures recorded for our portion of ownership were $7.5 million and $7.1 million for 2006 and 2005, respectively, excluding depreciation expenses. 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 unit’s 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.
We and Westar Generating, Inc. (“WGI”), a subsidiary of Westar Energy, Inc., share joint ownership of a 500-megawatt combined cycle unit at the State Line Power Plant (the “State Line Combined Cycle Unit”). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs. At December 31, 2006 and 2005, our property, plant and equipment accounts include the cost of our ownership interest in the unit of $154.2 million and $153.3 million, respectively, and accumulated depreciation of $27.0 million and $22.6 million, respectively. Expenditures recorded for our portion of ownership were $49.3 million and $72.3 million for 2006 and 2005, respectively, excluding depreciation.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
12. Commitments and Contingencies
We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5). In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse affect upon our financial condition, or results of operations or cash flows.
Coal, Natural Gas and Transportation Contracts
We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. The firm physical gas and transportation commitments total $59.4 million for 2007, $65.5 million for 2008 through 2009, $45.4 million for 2010 through 2011 and $79.5 million for 2012 and beyond. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price.
We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements are $27.8 million for 2007, $33.1 million for 2008 through 2009 and $6.8 million for 2010 through 2011.
Purchased Power
We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.
We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $55.3 million through May 31, 2010.
We also have a long term agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. We have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. Commitments under this contract total approximately $53.0 million through December 31, 2015.
New Construction
On March 14, 2006, we entered into contracts to purchase an undivided interest in 50 megawatts of the Plum Point Energy Station’s new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. The estimated cost is approximately $103 million in direct costs, including AFUDC. In addition, we entered into an agreement with KCP&L on June 13, 2006 to purchase an undivided ownership interest in the proposed coal-fired Iatan 2. We will own 12%, or approximately 100 megawatts, of the proposed 850-megawatt unit. Our share of the Iatan 2 costs will range from approximately $183.6 million to $200.5 million, excluding AFUDC.
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Leases
On December 10, 2004, we entered into a 20-year contract with Elk River Windfarm, LLC to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or 10% of our annual needs under the contract, which was declared commercial on December 15, 2005. We do not own any portion of the windfarm. Payments for wind energy from the Elk River Windfarm are contingent upon output of the facility. Payments can run from zero to a maximum of $15.2 million based on a 20 year average cost and the estimated output of 550,000 megawatt hours. These costs are recorded as purchased power expenses, and are not included in the operating lease obligations shown below.
We also currently have short-term operating leases for two unit trains to meet coal delivery demands and for five service center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment.
Our obligations over the next five years are as follows:
Expenses incurred related to operating leases were $0.9 million, $0.7 million and $0.6 million for 2006, 2005 and 2004, respectively. The accumulated amount of amortization for our capital leases was $0.2 million at December 31, 2006
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
Environmental Matters
We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and wastes, including their identification, transportation, disposal, record-keeping and reporting, including asbestos, as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.
Electric Segment
Air. The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan Power Plants and Units 3 and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx). The Asbury Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired boiler on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an affected unit for SO2 and NOx on January 1, 2000. Units 3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003. The new Riverton Unit 12 became an affected unit in January 2007.
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
THE EMPIRE DISTRICT ELECTRIC COMPANY
Notes to Consolidated Financial Statements (Continued)
monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances.
SO2 emissions will be further regulated as described in the Clean Air Interstate Rule section below.
NOx Emissions. The Asbury, Iatan, State Line, Energy Center and Riverton Plants are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated.
The Asbury Plant received permission from the Missouri Department of Natural Resources (MDNR) to burn TDF at a maximum rate of 2% of total fuel input. During 2006, approximately 5,794 tons of TDF were burned. This is equivalent to 579,400 discarded passenger car tires.
Under the MDNR’s Missouri NOx Rule, our Iatan, Asbury, State Line and Energy Center facilities, like other facilities in Western Missouri, are generally subject to a maximum NOx emission rate of 0.35 lbs/mmBtu. However, facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are only subject to a higher NOx emission limit of 0.68 lbs/mmBtu. All of our plants currently meet the required emission limits and additional NOx controls are not required.
NOx is further regulated as described in the Clean Air Interstate Rule below.
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 to Enerfab, Inc. 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.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 EPA’s February 16, 2004 regulations. At this time, the schedule for reconsideration and revisions is not known. We will be engaged with the EPA in its reconsideration and revision process. Data collection will continue under the PIC and will be expanded as needed to limit increased costs, if any, due to the EPA’s reconsiderations. At this time, we do not expect costs associated with compliance to be material.
Other. Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site’s total emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Plants. We submitted the required renewal applications for
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan is required by the renewed permit for Asbury. We estimate that the capital costs associated with the CAM plan will not exceed $2 million.
A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and the to-be-constructed Iatan Unit No. 2. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit only allows Unit No. 1 to produce a total of 652 net megawatts and, as a result, our share decreased from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and baghouse are completed, currently estimated to be late in the fourth quarter of 2008.
Gas Segment
The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri (the MDNR Registry). Site #2 has received a letter of no further action from the MDNR. We are reviewing various actions that may be undertaken to reduce environmental and health risks associated with the MDNR Registry site.
13. Segment Information
We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company is our wholly owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. The other segment consists of our businesses which are unregulated and include a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business and a 100% interest in Fast Freedom, Inc., an Internet provider.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As discussed in “Note 18 - Discontinued Operations,” we sold our controlling 52% interest in MAAP to other current owners on August 31, 2006. MAPP is a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. We also sold our interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software. For financial reporting purposes, both of these businesses have been classified as a discontinued operation and are not included in our segment information.
(1) Does not include the acquisition of Missouri gas operation.
(1) Includes goodwill of $39,323.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Selected Quarterly Information (Unaudited)
The following is a summary of quarterly results for 2006 and 2005.
The sum of the quarterly earnings per share of common stock may not equal the earnings per share of common stock as computed on an annual basis due to rounding.
15. Risk Management and Derivative Financial Instruments
We utilize derivatives to manage our natural gas commodity market risk. This helps manage our exposure resulting from purchasing natural gas, to be used as fuel and natural gas distribution, on the volatile spot market and to manage certain interest rate exposure.
As of December 31, 2006 and 2005, we have recorded the following assets and liabilities representing the fair value of qualifying derivative financial instruments held as of that date, which have been designated as cash flow hedges.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Derivative Summary
An $8.8 million net of tax, unrealized gain representing the fair market value of these derivative contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of December 31, 2006. The tax effect of $5.4 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning January 1, 2007 and ending on September 30, 2011. At the end of each contract settlement period, any gain or loss for that period related to the instrument will be reclassified to fuel expense. Approximately $1.5 million is applicable to financial instruments which will settle within the next year.
We record unrealized gains/(losses) on the overhedged portion of our gas hedging activities for our electric segment in “Fuel” under the Operating Revenue Deductions section of our income statements since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. Corresponding gains and losses for the gas segment are recorded to a regulatory asset or liability account.
The following table sets forth “mark-to-market” pre-tax gains/(losses) from the overhedged portion of our electric segment hedging activities and the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts included in “Fuel”:
The table above does not include a $1.4 million realized loss from an interest rate derivative contract in June 2005. The benefit and cost of these transactions are recorded as interest expense as amortized. See Note 7 “Long-Term Debt” for information on our hedging of interest rate exposures.
We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases. We have instituted a process to determine if any future executed
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly.
16. Accounts Receivable - Other
The following table sets forth the major components comprising “accounts receivable - other” on our consolidated balance sheet (in thousands):
(1) The accounts receivable for energy trading margin deposit represents the balance in our brokerage account as of December 31, 2006. NYMEX futures contracts are used in our hedging program of natural gas which require posting of margin.
(2) The $0.9 million in accounts receivable for true-up on maintenance contracts represents quarterly estimated credits due from Siemens Westinghouse related to our maintenance contract entered into in July 2001 for State Line Combined Cycle Unit (SLCC). Forty percent of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of December 31, 2006.
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Regulated - Other Operating Expense
The following table sets forth the major components comprising “regulated - other” under “Operating Revenue Deductions” on our consolidated statements of income for all periods presented:
(1) Does not include capitalized portion or amount deferred to a regulatory asset.
18. Discontinued Operations
In August 2006, we sold our controlling 52% interest in MAPP to other current owners. MAPP is a company that 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. We have reported MAPP and Conversant’s results as discontinued operations. A summary of the components of losses from discontinued operations for the years ended December 31, 2006, 2005 and 2004 follows (in thousands):
THE EMPIRE DISTRICT ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19. Subsequent Events
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.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9 A.
ITEM 9 A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2006. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Management has excluded The Empire District Gas Company from its assessment of internal control over financial reporting as of December 31, 2006 because it was acquired by the Company in a purchase business combination during 2006. The Empire District Gas Company is a wholly-owned subsidiary whose total assets and total revenues represent 9.5% and 6.1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2006.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the fourth quarter of 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9 B.
ITEM 9 B. OTHER INFORMATION
None
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE
Except as set forth below, the information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 26, 2007, which is incorporated herein by reference.
Pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under “Executive Officers and Other Officers of Empire.”
We have adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. This code was amended and approved by our board of directors on February 1, 2007. A copy of the amended code is available on our website at www.empiredistrict.com. Any future amendments or waivers to the code will be posted on our website at www.empiredistrict.com.
Because our common stock is listed on the NYSE, our Chief Executive Officer is required to make a CEO’s Annual Certification to the NYSE in accordance with Section 303A.12 of the NYSE Listed Company Manual stating that he is not aware of any violations by us of the NYSE corporate governance listing standards. Our Chief Executive Officer has provided, and intends to continue to timely provide, the NYSE with the CEO’s Annual Certification.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 26, 2007, which is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Except as set forth below, information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 26, 2007, which is incorporated herein by reference.
There are no arrangements the operation of which may at a subsequent date result in a change in control of Empire.
Securities Authorized For Issuance Under Equity Compensation Plans
We have four equity compensation plans, all of which have been approved by shareholders, the 1996 Stock Incentive Plan, the 2006 Stock Incentive Plan, the Employee Stock Purchase Plan (ESPP) and the Stock Unit Plan for Directors.
The following table summarizes information about our equity compensation plans as of December 31, 2006.
(1) The weighted average exercise price of $21.73 relates to 39,100 and 54,200 options granted to executive officers in 2005 and 2004, respectively, under the 1996 Stock Incentive Plan, 41,700 options granted to executive officers in 2006 under the 2006 Stock Incentive Plan and 38,707 subscriptions outstanding for our ESPP. The two stock incentive plans had a weighted average exercise price of $22.21 and the ESPP had an exercise price of $20.05. There is no exercise price for 77,600 performance-based stock awards awarded under the 1996 and 2006 Stock Incentive Plans or for 82,680 units awarded under the Stock Unit Plan for Directors.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 26, 2007, which is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 26, 2007, which is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Index to Financial Statements and Financial Statement Schedule Covered by Report of
Independent Registered Public Accounting Firm
Consolidated balance sheets at December 31, 2006 and 2005
Consolidated statements of income for each of the three years in the period ended December 31, 2006
Consolidated statements of comprehensive income for each of the three years in the period ended December 31, 2006
Consolidated statements of common shareholders’ equity for each of the three years in the period ended December 31, 2006
Consolidated statements of cash flows for each of the three years in the period ended December 31, 2006
Notes to consolidated financial statements
Schedule for the years ended December 31, 2006, 2005 and 2004:
Schedule II - Valuation and qualifying accounts
All other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is included in the financial statements or notes thereto.
List of Exhibits
(3)(a)
The Restated Articles of Incorporation of Empire (Incorporated by reference to Exhibit 4(a) to Registration Statement No. 33-54539 on Form S-3).
(b)
By-laws of Empire as amended October 31, 2002 (Incorporated by reference to Exhibit 4(b) to Annual Report on Form 10-K for year ended December 31, 2002, File No. 1-3368).
(4)(a)
Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto among Empire, The Bank of New York and UMB Bank, N.A., (Incorporated by reference to Exhibits B(1) and B(2) to Form 10, File No. 1-3368).
(b)
Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).
(c)
Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).
(d)
Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Form S-3, File No. 33-56635).
(e)
Twenty-Second Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(k) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1-3368).
(f)
Twenty-Third Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(l) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1-3368).
(g)
Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1-3368).
(h)
Twenty-Fifth Supplemental Indenture dated as of November 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(p) to Registration Statement No. 33-56635 on Form S-3).
(i)
Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Annual Report on Form 10-K for year ended December 31, 1996, File No. 1-3368).
(j)
Twenty-Ninth Supplemental Indenture dated as of April 1, 1998 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1998, File No. 1-3368).
(k)
Indenture for Unsecured Debt Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank Minnesota, National Association (Incorporated by reference to Exhibit 4(v) to Registration Statement No. 333-87015 on Form S-3).
(l)
Securities Resolution No. 2, dated as of February 22, 2001, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-3368).
(m)
Securities Resolution No. 3, dated as of December 18, 2002, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for year ended December 31, 2002, File No. 1-3368).
(n)
Securities Resolution No. 4, dated as of June 10, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K dated June 10, 2003 and filed June 29, 2003, File No. 1-3368).
(o)
Securities Resolution No. 5, dated as of October 29, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for quarter ended September 30, 2003).
(p)
Securities Resolution No. 6, dated as of June 27, 2005, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K filed on June 28, 2005, File No. 1-3368).
(q)
Rights Agreement dated as of April 27, 2000 between Empire and Mellon Investor Services LLC (Incorporated by reference to Exhibit 4 to Form 10-Q for the quarter ended March 31, 2000, File No. 1-3368).
(r)
First Amended and Restated Unsecured Credit Agreement, dated as of March 14, 2006, among Empire, UMB Bank, N.A., as arranger and administrative agent, Bank of America, N.A., as syndication agent, and the lenders named therein (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 16, 2006, File No. 1-3368).
(s)
Bond Purchase Agreement dated June 1, 2006 among The Empire District Gas Company and thepurchasers party thereto (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8- K filed on June 6, 2006, File No. 1-3368).
(t)
Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company, N.A., Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed on June 6, 2006, File No. 1-3368).
(u)
First Supplemental Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company, N.A., Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed on June 6, 2006, File No. 1-3368).
(10)(a)
1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639).
(b)
2006 Stock Incentive Plan (Incorporated by reference to Exhibit 4(u) to Form S-8, File No. 333-130075).
(c)
Deferred Compensation Plan for Directors (Incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1-3368).
(d)
The Empire District Electric Company Change in Control Severance Pay Plan as amended and restated effective January 1, 2001.*
(e)
Form of Severance Pay Agreement under The Empire District Electric Company Change in Control Severance Pay Plan.*
(f)
The Empire District Electric Company Supplemental Executive Retirement Plan. (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for year ended December 31, 1994, File No. 1-3368).
(g)
Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form 10-Q for quarter ended September 30, 1998, File No. 1-3368).
(h)
Stock Unit Plan for Directors of The Empire District Electric Company (Incorporated by reference to Exhibit 10(i) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368)..
(i)
Summary of Annual Incentive Plan (Incorporated by reference to Exhibit 10(j) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368).
(j)
Form of Notice of Award of Dividend Equivalents (Incorporated by reference to Exhibit 10(k) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368).
(k)
Form of Notice of Award of Non-Qualified Stock Options (Incorporated by reference to Exhibit 10(l) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368).
(l)
Form of Notice of Award of Performance-Based Restricted Stock (Incorporated by reference to Exhibit 10(m) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368).
(m)
Summary of Compensation of Non-Employee Directors (Incorporated by reference to Exhibit 10(n) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368).
(12)
Computation of Ratios of Earnings to Fixed Charges.*
(21)
Subsidiaries of Empire*
(23)
Consent of PricewaterhouseCoopers LLP*
(24)
Powers of Attorney.*
(31)(a)
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
(31)(b)
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
(32)(a)
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~
(32)(b)
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~
 This exhibit is a compensatory plan or arrangement as contemplated by Item 15(a)(3) of Form 10-K.
* Filed herewith
~ This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.
SCHEDULE II
Valuation and Qualifying Accounts
Years ended December 31, 2006, 2005 and 2004
NOTE A: This reserve is provided for workers’ compensation, certain postemployment benefits and public liability damages. At December 31, 2006, we carried insurance for workers’ compensation claims in excess of $500,000 and for public liability claims in excess of $500,000. The injuries and damages reserve is included on the Balance Sheet in the section “Noncurrent liabilities and deferred credits” in the category “Other”.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Date
/s/ WILLIAM L. GIPSON
William L. Gipson, President,
Chief Executive Officer, Director
(Principal Executive Officer)
/s/ GREGORY A. KNAPP
Gregory A. Knapp, Vice President-Finance
(Principal Financial Officer)
/s/ LAURIE A. DELANO
Laurie A. Delano, Controller, Assistant
Secretary and Assistant Treasurer
(Principal Accounting Officer)
/s/ DR. JULIO S. LEON*
Dr. Julio S. Leon, Director
/s/ KENNETH R. ALLEN*
Kenneth R. Allen, Director
/s/ MYRON W. MCKINNEY*
Myron W. McKinney, Director
/s/ ROSS C. HARTLEY*
March 1,
Ross C. Hartley, Director
/s/ D. RANDY LANEY*
D. Randy Laney, Director
/s/ BILL D. HELTON*
Bill D. Helton, Director
/s/ B. THOMAS MUELLER*
B. Thomas Mueller, Director
/s/ ALLAN T.THOMS*
Allan T. Thoms, Director
/s/ MARY McCLEARY POSNER*
Mary McCleary Posner, Director
/s/ GREGORY A. KNAPP
*By (Gregory A. Knapp, As attorney in fact for
each of the persons indicated)