Item 1.
Business
SEMCO Energy, Inc.
The Company is a New York Stock Exchange (“NYSE”)-listed regulated public utility company headquartered in Port Huron, Michigan. It was founded in 1950 as Southeastern Michigan Gas Company (“SMGC”). In 1977, the Company initiated a reorganization, pursuant to which Southeastern Michigan Gas Enterprises, Inc. (“SMGE”) was formed and SMGC became a wholly-owned subsidiary of SMGE. On April 24, 1997, SMGE’s name was changed to SEMCO Energy, Inc. and SMGC’s name was changed to SEMCO Energy Gas Company. On January 1, 2000, SEMCO Energy Gas Company was merged into SEMCO Energy, Inc. References to the “Company” in this document mean SEMCO Energy, Inc., its subsidiaries, divisions or the business segments discussed below as appropriate in the context of the disclosure.
The Company operates one reportable business segment: Gas Distribution. The Gas Distribution business segment includes the Company’s natural gas distribution operations in Michigan and Alaska. The Company’s other business segments do not meet the quantitative thresholds to be reportable business segments (“non-separately reportable business segments”) and are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company’s non-separately reportable business segments primarily include operations and investments in information technology (“IT”) services, propane distribution, intrastate natural gas pipelines, and a natural gas storage facility. For further information on the Company’s business segments, refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Pending Sale of the Company
On February 22, 2007, the Company entered into an Agreement and Plan of Share Exchange (the “Exchange Agreement”) by and among the Company, Cap Rock Holding Corporation (“Cap Rock”) and Semco Holding Corporation, a direct wholly-owned subsidiary of Cap Rock (“Parent”), under which Parent will acquire all the outstanding Common Stock and 5% Series B Convertible Cumulative Preferred Stock (“Preferred Stock”) of the Company. Pursuant to the terms of the Exchange Agreement, each issued and outstanding share of Common Stock and Preferred Stock of the Company will be transferred to Parent. The Common Stock will be transferred for the right to receive $8.15 in cash per share, without interest, and the Preferred Stock will be transferred for the right to receive approximately $213.07 in cash per share plus a make-whole premium to be calculated at closing, without interest (collectively, the “Exchange Consideration”), in each case on the terms and subject to the conditions set forth in the Exchange Agreement (collectively, the “Share Exchange”). The Board of Directors of the Company (“Board”), upon the unanimous recommendation of its Finance Committee (which is comprised entirely of independent directors), approved the Exchange Agreement and has recommended that the holders of the Company’s Common Stock approve the Share Exchange at a special meeting to be held at a future date determined in accordance with the Exchange Agreement.
The Company has made customary representations, warranties and covenants in the Exchange Agreement. The Exchange Agreement contains a “go shop” provision pursuant to which the Company has the right to solicit and engage in discussions and negotiations with respect to competing acquisition proposals for 35 days following the date of the Exchange Agreement. In accordance with the Exchange Agreement, the Board, through its Finance Committee and with the assistance of the Company’s advisors, intends to solicit superior proposals during this period. There can be no assurance that the solicitation of superior proposals will result in an alternative transaction.
Following the “go shop” period, as it may be extended, the Company is subject to a “no shop” restriction on its ability to solicit third-party proposals, provide information and engage in discussions and negotiations with third parties. The no shop provision is subject to a “fiduciary out” provision that allows the Company to provide information and participate in discussions and negotiations with respect to third-party acquisition proposals
submitted after the “go shop” period that the Board believes in good faith, after consultation with its financial advisors and outside counsel, constitute or could reasonably be expected to result in a “superior proposal,” as defined in the Exchange Agreement.
The Company may terminate the Exchange Agreement under certain circumstances, including if the Board determines in good faith that it has received a “superior proposal” and that failure to terminate the Exchange Agreement would be inconsistent with its fiduciary duties, and the termination otherwise complies with certain terms of the Exchange Agreement. In connection with such termination, the Company must pay a termination fee to Parent and reimburse Parent for its out-of-pocket expenses, subject to a cap. The amount of such termination fee and expense reimbursement will depend on whether such termination is in connection with a “superior proposal” submitted during or after the “go-shop” period.
Consummation of the Share Exchange is not subject to a financing condition, but is subject to various other conditions, including approval of the Share Exchange by the holders of the Company’s Common Stock, approval by the Regulatory Commission of Alaska, expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and satisfaction of other customary closing conditions.
Gas Distribution Business Segment
The Company’s Gas Distribution business segment consists of natural gas distribution operations in Michigan and Alaska. The Michigan operation is sometimes referred to as “SEMCO Gas” and the Alaska operation is sometimes referred to as “ENSTAR.” These operations are referred to together as the “Gas Distribution Business.”
SEMCO Gas is a division of the Company. The ENSTAR operation includes ENSTAR Natural Gas Company, Alaska Pipeline Company (“APC”) and NORSTAR Pipeline Company (“NORSTAR”). ENSTAR Natural Gas Company is a division of the Company. APC is a subsidiary of the Company and NORSTAR is a subsidiary of APC. APC’s transmission system delivers natural gas from producing fields in South Central Alaska to ENSTAR’s Anchorage-area gas distribution system. APC’s only customer is ENSTAR. Historically, the RCA has regulated ENSTAR and APC as a single entity. NORSTAR began operations in 2002 and provides pipeline management and pipeline construction management services to non-affiliated customers in Alaska.
The Gas Distribution Business purchases, transports, distributes, and sells natural gas to residential, commercial and industrial customers and is the Company’s largest business segment. The Company’s strategy for the existing Michigan and Alaska gas distribution operations is to expand its transmission and distribution system in an economical manner through appropriate system improvements and the attachment of new customers located on or near gas mains within the Company’s existing service territories. For further information on the Company’s business strategy refer to the section entitled “Business Strategy Summary” within “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K. Set forth in the following table is financial and operating information for the Gas Distribution Business:
(a)
MMcf is a quantity of natural gas equal to one million standard cubic feet.
(b)
Degree days are a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the number of degree days incurred during each day of the period. The Company determines the percent (%) that weather is warmer or colder than normal for a particular period by computing the deviation of actual degree days for that period from the average of degree days during the prior fifteen-year period and dividing the deviation by such fifteen-year average. For the Company’s Alaska operations, beginning in 2006,
the Company determines the percent (%) that weather is warmer or colder than normal for a particular period by computing the deviation of actual degree days for that period from the average of degree days during the prior ten-year period and dividing the deviation by such ten-year average. Degree days are an indicator of natural gas consumption, since natural gas supplied and delivered by the Company is used by many customers for space heating, and heating consumption is affected by how warm or cold it is.
All revenue generated by the Gas Distribution Business for the years ended December 31, 2006, 2005, and 2004, is from non-affiliated customers, except for an inconsequential amount, typically less than 0.05% per year. Refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K, for the operating revenues, operating income, assets and other financial information of the Gas Distribution Business for the past three years.
Rates and Regulation. The Gas Distribution Business is subject to regulation. The Michigan Public Service Commission (“MPSC”) has jurisdiction over the regulatory matters related to the Company’s Michigan customers, except for customers located in the City of Battle Creek and nearby communities. The regulatory matters related to customers located in the City of Battle Creek and nearby communities are currently subject to the jurisdiction of the City Commission of Battle Creek (“CCBC”). Regulatory matters related to customers in Alaska are subject to the jurisdiction of the Regulatory Commission of Alaska (“RCA”). These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures, and standards of service. The approximate number of the Company’s customers located in service areas regulated by each of the three regulatory bodies is as follows: MPSC - 250,000; CCBC - 37,000; and RCA - 126,000. In May 2006, the Company and CCBC filed a joint application with the MPSC requesting that the MPSC assume jurisdiction over the service territory currently regulated by the CCBC. The joint application asked the MPSC to approve the CCBC tariff, rates, charges and terms and conditions of service that are currently in effect. For information on this and other regulatory matters, including recent regulatory orders, filings and rate cases, refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Gas Sales. Gas sales revenue is generated primarily through the sale and delivery of natural gas to residential and commercial customers. These customers use natural gas mainly for space heating. Consequently, weather has a significant impact on sales. As a result of the impact of weather on the Gas Distribution business segment, most of the Company’s gas sales revenue is generated in the first and fourth quarters of the calendar year. Revenues from gas sales accounted for 93% of consolidated operating revenues in 2006 and 2005 and 91% of consolidated operating revenues in 2004.
In Michigan, the MPSC has approved a program known as the Gas Customer Choice Program, which allows gas sales customers to purchase natural gas from third-party suppliers, while allowing the Company to continue charging these customers existing distribution charges and customer fees plus a gas load balancing fee. As a result, the Company’s earnings are generally not materially affected by customers switching from gas sales service to the Gas Customer Choice Program. The program is available to all gas sales customers in the Company’s service area regulated by the MPSC. There were 634 customers taking service under the Gas Customer Choice Program at December 31, 2006. There were no customers taking service under the Gas Customer Choice Program at December 31, 2005.
In Alaska, industrial and commercial customers also may purchase natural gas from third-party suppliers. The Company charges the same distribution charges and customer fees for gas transportation service to these customers as it does for gas sales service. As a result, the Company’s earnings are generally not materially affected by customers switching between gas sales service to gas transportation service. At December 31, 2006, and 2005, there were, approximately 900 and 1,600 customers in Alaska, respectively, who were utilizing commercial transportation service. The decrease in the number of customers utilizing transportation service in Alaska was due primarily to customers switching from gas transportation service to gas sales service because a third-party supplier stopped supplying natural gas to these customers in late-2006. The gas for these new sales customers is being supplied under the Company’s existing long-term gas supply agreements.
Gas Transportation. The Gas Distribution Business provides transportation services to its large-volume commercial and industrial customers. This service allows those customers to purchase gas directly from third-party suppliers. The natural gas purchased by customers from third-party suppliers is then transported on the Company’s
gas transmission and distribution network to the customers. Unlike gas sales service, the amount the Company charges its transportation service customers does not include the cost of gas because these customers are not purchasing natural gas from the Company. Transportation services are also available to smaller volume customers who participate in the Gas Customer Choice Program in Michigan and commercial customers who elect transportation service in Alaska, as described under the caption “Gas Sales,” above.
Customer Base. At December 31, 2006, the Gas Distribution Business had approximately 413,000 customers, including 287,000 customers in Michigan and 126,000 customers in Alaska. Customers in Michigan are located in southeastern Michigan, just northeast of the metro-Detroit area, and in various areas throughout the state, including Albion, Battle Creek, Holland, Houghton, Marquette, Niles, Ontonagon, St. Ignace and Three Rivers. Customers in Alaska are located in and around the Anchorage and Cook Inlet area, including Big Lake, Bird Creek, Butte, Chugiak, Eagle River, Eklutna, Girdwood, Houston, Indian, Kasilof, Kenai, Knik, Nikiski, Palmer, Peters Creek, Portage, Sterling, Soldotna, Wasilla and Whittier. ENSTAR distributes natural gas to the greater Anchorage metropolitan area, and its service area encompasses over 56% of the population of Alaska.
The customer base of the Gas Distribution Business includes residential, commercial and industrial customers. The largest customers in Michigan include power plants, food production facilities, paper processing plants, furniture manufacturers and others in a variety of industries. The largest customers in Alaska include power plants, a liquefied natural gas (“LNG”) plant, a refinery and a fertilizer plant. For further discussion on the potential loss of the fertilizer plant as a customer, refer to the caption “Natural Gas Supply” in Item 1 of this Form 10-K. The average number of customers at SEMCO Gas (excluding customers acquired in the acquisition of Peninsular Gas Company (“Peninsular Gas”) in 2005) has increased by an average of approximately 1.1% annually during the past three years (0.6% in 2006), and the average number of customers at ENSTAR has increased by an average of approximately 3.3% annually during the past three years (3.2% in 2006). Average annual gas consumption per customer in both Michigan and Alaska generally has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances. In addition, recent increases in natural gas prices appear to have prompted customers to reduce their gas consumption. For additional information on the impact of higher natural gas prices, refer to the caption “The Impact of Higher Natural Gas Prices” in Item 7 of this Form 10-K.
Competition. Competition in the gas sales market generally arises from alternative energy sources, such as electricity, propane and oil. However, this competition is generally inhibited because of the time, inconvenience and investment necessary for residential and commercial customers to convert to an alternative energy source even as the price of natural gas fluctuates. For residential and commercial gas sales customers, natural gas typically is the most economical energy source for heating in the areas served by the Company.
Competition in the gas transportation market generally arises from alternative energy sources, such as coal, electricity, oil and steam. Certain large industrial customers may be able to use one or more alternative energy sources or may shift production to facilities outside the Company’s service territories if the price of Company-provided natural gas and delivery services increases significantly compared to prices charged for such services elsewhere. Natural gas has typically been less expensive than these alternative energy sources. However, generally over the past three years and recently in a more significant way, natural gas prices have been higher and more volatile, making some of these alternative energy sources more economical or, for other reasons, more attractive than natural gas. During this period, certain of the Company’s large Michigan industrial customers have periodically switched to alternative energy sources.
To reduce the possibility of such fuel-switching and production-shifting by industrial customers, the Company offers flexible contract terms and additional services, such as gas storage and balancing. Partially offsetting the impact of this price sensitivity among certain large industrial customers has been the use of natural gas to reduce emissions from their plants.
There is a risk that industrial customers located in close proximity to interstate natural gas pipelines will bypass the Company’s transmission and distribution system by connecting directly to those pipelines. The Company has addressed, and expects to continue to address, any such efforts by offering flexible contract terms and additional services intended to retain these customers on the Company’s system. Gas sales, power plant and commercial transportation customers in ENSTAR’s service territory are currently precluded from bypassing ENSTAR’s
transportation and distribution system due to the limited availability of gas transmission systems and the distances between producing fields and the locations of current customers.
Natural Gas Supply. SEMCO Gas has access to natural gas supplies throughout the United States and Canada via major interstate and intrastate pipelines in and near Michigan. SEMCO Gas has pipeline capacity contracts with ANR Pipeline Company, Great Lakes Gas Transmission Limited Partnership, Northern Natural Gas Company, Panhandle Eastern Pipe Line Company, Trunkline Gas Company, LLC, Michigan Consolidated Gas Company and Consumers Energy Company. SEMCO Gas also owns underground storage facilities in Michigan with a working capacity of 5.1 billion cubic feet (“Bcf”). In addition, it leases 6.5 Bcf of storage from Eaton Rapids Gas Storage System (“ERGSS”) and 3.5 Bcf from non-affiliates in Michigan. The owned and leased storage capacity equals approximately 42% of the Company’s 2006 annual gas sales volumes in Michigan. SEMCO Gas Storage Company, a subsidiary of the Company, is a 50% owner of the ERGSS.
SEMCO Gas has negotiated standard terms and conditions for the purchase of natural gas under the North American Energy Standards Board (“NAESB”) form of agreement with a variety of suppliers, including BP Canada Energy Marketing Corp. (“BP”), Charlevoix Energy, Chevron U.S.A., ConocoPhillips, Coral Energy, Cornerstone Energy, Enbridge Marketing U.S., Fortis Energy Marketing and Trading, Husky Oil, Mid-American Energy, Nexen Marketing, Occidental Energy Marketing, Inc., OGE Energy, Ohio Gas Energy Services, ONEOK Energy, Peoples Energy Resources, Sequent Energy Management Co. and Tenaska Marketing. SEMCO Gas purchases natural gas under one or more of these agreements for resale to customers in Michigan, typically in accordance with a gas supply procurement plan approved by the MPSC for customers in areas regulated by the MPSC. The gas procurement process for customers in the service areas regulated by the CCBC and RCA is described below.
SEMCO Gas has an asset management agreement with BP covering the period of April 1, 2005, through March 31, 2008. Under the agreement, BP provides transportation and storage asset management services for the Company for customers in its service area regulated by the MPSC (“MPSC-regulated customers”) and customers in its service area regulated by the CCBC (“CCBC-regulated customers”).
The Company’s MPSC-regulated customers are charged for natural gas commodity costs through a gas cost recovery (“GCR”) pricing mechanism. The MPSC typically reviews and approves a gas supply procurement plan submitted annually by the Company, covering purchases from April 1 of one year to March 31 of the next year. These purchases include both gas supplies for use by customers, commitments to future gas deliveries, and storage injections and withdrawals. The Company’s MPSC-approved GCR gas purchase plans require the Company to solicit bids for all supplies.
The Company’s CCBC-regulated customers have been charged for natural gas commodity costs through a GCR-type pricing mechanism since April 1, 2005. The CCBC periodically audits the Company’s gas supply procurement plans, which are substantially similar to the ones used to procure gas supplies for MPSC-regulated customers.
For MPSC- and CCBC-regulated customers, all gas supplies purchased during each GCR period are based on a portfolio of short-term fixed price and short-term index price supply agreements. For information about how the GCR pricing mechanism and related MPSC reviews impact the cost of gas, refer to the “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” section within Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
ENSTAR has access to natural gas supplies in close proximity to its Alaska service territory. ENSTAR’s system, including the APC pipeline system, is not linked to major interstate and intrastate pipelines and natural gas supplies in other states or Canada. As a result, ENSTAR procures natural gas supplies under long-term, RCA-approved contracts, from producers in and near the Cook Inlet area. It also recovers gas supply costs through a GCR-type pricing mechanism.
ENSTAR has a gas purchase contract with Marathon Oil Company (“Marathon”) approved by the RCA (the “1988 Marathon Contract”). It is a requirements contract with no specified daily deliverability or annual take-or-pay quantities. Marathon is required to deliver up to 11 Bcf of gas in 2007. Each year thereafter, Marathon’s maximum delivery obligation decreases by 2 Bcf per year until 2010 when this delivery obligation will be 5 Bcf. The annual delivery obligation remains at 5 Bcf per year until the original commitment of 456 Bcf has been
exhausted, which is expected to be in 2018. The contract has a base price and is subject to an annual adjustment based on changes in the price of certain traded oil futures contracts plus reimbursement for severance taxes and other charges.
ENSTAR has RCA-approved gas purchase contracts with Anchorage Municipal Light and Power, Chevron U.S.A., Inc. and ConocoPhillips Alaska, Inc. that provide for the delivery of gas through the year 2009 from the Beluga natural gas field (collectively, the “Beluga Contract”). ENSTAR’s obligation to take gas under the Beluga Contract is estimated to be approximately 3.0 Bcf in 2007 and 4.0 Bcf in both 2008 and 2009. The pricing mechanism in the Beluga Contract is similar to the 1988 Marathon Contract.
ENSTAR has an RCA-approved gas supply contract with Aurora Gas LLC (“Aurora Gas”) for natural gas deliveries from the Moquawkie natural gas field (the “Moquawkie Contract”). The Moquawkie Contract provides that Aurora Gas will supply a portion of ENSTAR’s needs through 2014. However, in April 2006, the Company received a letter from Aurora Gas asserting that production under the Moquawkie Contract is “Not Economic” as that term is defined in the Moquawkie Contract. Aurora Gas said that it would suspend, and subsequently did suspend, deliveries effective October 1, 2006. Under the Moquawkie Contract, Aurora Gas was required to deliver up to 1.5 Bcf of natural gas in 2007. This requirement was to decline annually until the projected final year requirement of 0.2 Bcf in 2014. The total remaining commitment at the end of 2006 was approximately 5.9 Bcf. The Company has obtained substitute gas under the Company’s other gas supply contracts to replace Moquawkie Contract volumes Aurora Gas has not delivered, but this substitute gas has been at higher prices than provided for in the Moquawkie Contract. Refer to Note 2 and Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding the lawsuit the Company has filed against Aurora Gas and steps the Company has taken to recover the higher cost of the substitute gas.
ENSTAR also has an RCA-approved gas supply contract with Union Oil Company of California (“Unocal”) (the “Unocal Contract”). Natural gas deliveries under this contract began in 2004. The Unocal Contract provides that Unocal will supply all or a portion of ENSTAR’s requirements based upon additional commitments that may be made by Unocal annually in October. In October 2006, Unocal made a commitment to supply all of ENSTAR’s requirements not met by the 1988 Marathon and Beluga Contracts through 2008 and to supply 19.5 Bcf in 2009, 2010 and in 2011. In any year after 2011, Unocal cannot reduce its commitment by more than 3 Bcf per year. Under the terms of the Unocal Contract, Unocal must advise ENSTAR each October of Unocal’s commitments for the next five years. Each commitment of gas is subject to review by an independent petroleum engineer, but Unocal does not guarantee that it has reserves sufficient to meet its obligations. Under specified circumstances, Unocal may reduce or terminate its obligations to deliver gas. Gas supplied under the Unocal Contract is priced annually according to a 36-month daily average price of certain traded natural gas futures contracts, subject to a floor price. The Unocal Contract also provides for reimbursement for severance taxes and other charges.
ENSTAR entered into an additional gas supply agreement for its Alaska service area with Marathon (the “2005 Marathon Contract”). The 2005 Marathon Contract provided for natural gas deliveries to begin in 2009 and run through at least 2017, for a total of approximately 60 Bcf of natural gas. Gas supplied under the 2005 Marathon Contract was to be priced annually according to a 12-month daily average price of certain traded natural gas futures contracts, discounted if the average price exceeded $6.00 per thousand cubic feet (“Mcf”), and subject to indexed floor and ceiling prices. In November 2005, the Company submitted the 2005 Marathon Contract to the RCA for its approval. In an order issued in September 2006, the RCA rejected the 2005 Marathon Contract. In December 2006, the RCA issued an additional order that granted, in part, petitions for reconsideration of the RCA’s September 2006 order, but the RCA did not approve the contract. Marathon subsequently terminated the 2005 Marathon Contract. Refer to Note 2 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for information regarding these RCA decisions.
The Unocal, 1988 Marathon, and Beluga Contracts collectively provide for all of ENSTAR’s supply requirements through 2008. After 2008, gas will still be available under those contracts in accordance with their terms, but at least a portion of ENSTAR’s requirements is expected to be met by amendments to those contracts or by new contracts. In February 2007, ENSTAR issued a request for gas supply proposals as a result of the actions taken by the RCA and Marathon with respect to the 2005 Marathon Contract. ENSTAR is currently in discussions
with several parties, including Marathon, to secure additional natural gas supplies. Any resulting contracts would be submitted to the RCA for approval.
Production from the Cook Inlet area natural gas fields is declining, and new discoveries have been modest. As of January 1, 2006, the Cook Inlet area had approximately 1.6 trillion cubic feet (“Tcf”) of total proven natural gas reserves according to the most recently available information contained in the Alaska Department of Natural Resources Division of Oil and Gas 2006 Annual Report. Based on the Department’s reported 2005 net production of 209 Bcf, there was a reserve life at January 1, 2006, of approximately 8 years in the Cook Inlet area, although shortages of daily deliverability have occurred, resulting in curtailment of some industrial loads (which were not served by ENSTAR) during cold weather periods. There is ongoing exploration for natural gas in the Cook Inlet area, including by producers that have supply contracts with ENSTAR. This exploration is confined to areas in or near producing fields. The United States Geological Survey and Minerals Management Service has estimated that the Cook Inlet area contains approximately 2.3 Tcf of undiscovered natural gas, but there are no assurances that any of this natural gas will be discovered and, if discovered, can be produced economically and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.
Approximately 115 Bcf of natural gas are exported each year from Cook Inlet in the form of LNG and ammonia-urea fertilizer. The owner of the fertilizer plant has publicly announced that it has experienced difficulty in securing sufficient natural gas supplies at an appropriate price to continue operating in the future. The owner of the plant has said that it has secured sufficient natural gas supplies to operate at a reduced rate through October 2007, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. Furthermore, the fertilizer plant shut down operations in October 2006 and is expected to remain shut down through March 2007, due to the lack of seasonal gas supply. In addition, the owners of the LNG plant have filed for a two-year extension of its export license, which currently expires on March 31, 2009. The Company cannot predict the likely pattern of future operations at these two plants, including whether the fertilizer plant will ultimately close or whether the export license for the LNG plant will be renewed. Further, activity continues with respect to the possible construction of a natural gas pipeline that would extend from Alaska’s North Slope, through central Alaska and Canada, to the lower 48 states of the United States. Assuming this pipeline is built, the flow of natural gas through it could not be expected to begin before the middle of the next decade, at the earliest. ENSTAR is engaged in an effort to make customers and public officials aware of the importance of the North Slope natural gas pipeline and the need to make North Slope natural gas available in the Cook Inlet area using this pipeline or otherwise. The Company can provide no assurances, however, with respect to the construction of this or another pipeline, when such a pipeline would be put in service, or whether natural gas supplies transported by such a pipeline would be available to ENSTAR customers and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.
Environmental Matters. Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. Residual byproducts of these processes may have caused environmental conditions that require investigation and remediation. The Company owns seven sites in Michigan where such manufactured gas plants were located. Even though the Company never operated manufactured gas facilities at four of the sites, and did so at one site for only a brief period of time, the Company is subject to local, state and federal laws and regulations that require, among other things, the investigation and, if necessary, the remediation of contamination associated with these sites, irrespective of fault, legality of initial activity, or ownership, and which may impose liability for damage to natural resources. The Company has complied with the applicable Michigan Department of Environmental Quality (“MDEQ”) requirements, which require current landowners to mitigate unacceptable risks to human health from the byproducts of manufactured gas plant operations and to notify the MDEQ and adjacent property owners of potential contaminant migration. The Company is currently investigating these sites and anticipates conducting any necessary additional investigatory and remediation activities as appropriate. The Company has already remediated and closed a site related to one of the manufactured gas plant sites, with the MDEQ’s approval.
The Company is also attempting to identify other potentially responsible parties to bear some or all of the costs and liabilities associated with the investigatory and remediation activities at several of these sites and also is pursuing recovery of the costs of these activities from insurance carriers. The Company is unable to predict, however, whether and to what extent it will be successful in involving other potentially responsible parties in
investigatory or remediation activities, or in bearing some or all of the costs thereof, or in securing insurance recoveries for some or all of the costs associated with these sites.
The Company accrues for costs associated with environmental investigation and remediation obligations when such costs are probable and reasonably estimable. Accruals for estimated costs for environmental remediation obligations are generally recognized no later than the completion of the Company’s Remedial Action Plan (“RAP”) for a site. Such accruals are expected to be adjusted as further information becomes available or circumstances change. At three of the sites, the Company has begun efforts to determine the extent of remediation, if any, that must be performed, with the expectation of completing and submitting a RAP for each of the sites to the MDEQ. As a result of investigational work performed to date, the Company’s Consolidated Statements of Financial Position include an accrual and a corresponding regulatory asset in the amount of $1.6 million at December 31, 2006, for estimated environmental investigation and remediation costs that it believes are probable at these three sites. The Company has not discounted this accrual to its present value. The accrued costs are expected to be paid out over the next three years.
The accrual of $1.6 million represents what the Company believes is probable and reasonably estimable. However, the Company also believes that it is reasonably possible that there could be up to an estimated $18.5 million of environmental investigation and remediation costs for these three sites, in addition to the $1.6 million already accrued. It is also reasonably possible that the amount accrued or the reasonably possible range of costs may change in the future as the Company’s investigation of these sites continues and any remediation activities are undertaken. The Company’s cost estimates have been developed using probabilistic modeling, advice from outside consultants, and judgment by management. The liabilities estimated by the Company are based on a current understanding of the costs of investigation and remediation. Actual costs, which may differ materially from these estimates, may vary depending on, among other factors, the environmental conditions at each site, the level of any remediation required, and changes in applicable environmental laws.
The Company has done less investigational and remediation work at the remaining four sites but has met all applicable MDEQ requirements. The Company believes that further investigation and any remediation of environmental conditions at these sites may be the obligation of other potentially responsible parties. It is reasonably possible that the Company’s current estimate concerning costs likely to be incurred in connection with the investigation and any remediation of conditions at these four sites may change in the future as new information becomes available and circumstances change, including the Company’s further evaluation of the obligations of other potentially responsible parties for these costs. If this were to occur, the Company’s liability with respect to costs at these four sites could be material.
In accordance with an MPSC accounting order, the payment by the Company of environmental assessment and remediation costs associated with certain manufactured gas plant sites and other environmental expenses are deferred and amortized over ten years. Rate recognition of the related amortization expense does not begin until the costs are subject to review in a base rate case.
Corporate and Other
Corporate and Other includes the Company’s corporate division and non-separately reportable business segments. These non-separately reportable businesses are organized as subsidiaries of SEMCO Energy, Inc. and generally complement the Company’s Gas Distribution Business. Refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K, for operating revenues, operating income, assets and other financial information for Corporate and Other for the past three years.
The Company’s IT business operation is located in Michigan and provides IT services with a primary focus on the Company’s IT needs. For 2006, these services included the implementation of a new Customer Information System and related system changes and upgrades. The Company does not currently provide IT services to non-affiliated customers but may do so in the future where it believes that it can do so profitably.
The Company owns a propane distribution business known as “Hotflame.” Hotflame typically supplies approximately 4 million gallons of propane annually to retail customers in Michigan’s Upper Peninsula and northeast Wisconsin. Because propane is used principally for heating, most of the operating income for the propane
business is generated in the first and fourth quarters of the calendar year. Propane is transported in pressurized containers and is generally used in rural areas where natural gas pipelines and distribution systems do not exist or are not economical to build. The Company has access to a variety of propane suppliers, including NGL Supply, Inc., Alliance, and Amerigas. The propane operation competes with other energy sources, such as natural gas, fuel oil, electricity and other regional and national propane providers, generally based on the availability of alternative energy sources, price and service.
The Company’s pipelines and storage business consists of three pipelines and a gas storage facility, all of which are located in Michigan. The Company has a partial ownership interest in one of the pipelines and an equity interest in the gas storage facility. Refer to Item 2 of this Form 10-K for additional information on each pipeline and the storage facility.
The Company’s corporate division is a cost center rather than a business segment. The operating expenses of the corporate division that relate to the ongoing operations of the Company’s business segments are allocated to those business segments using a formula that is accepted by the regulatory bodies that have jurisdiction over the Gas Distribution Business. Examples of functions performed by the corporate division on behalf of the Company’s business segments include administration, human resources, legal, treasury, finance and accounting. Any corporate expenses that do not relate to the ongoing operations of the Company’s business segments or are not allocable to them under various regulatory rules are not allocated to these segments but remain on the books of the corporate division.
Miscellaneous Information
The Company had approximately 569 full-time employees at December 31, 2006, compared to 566 full-time employees at December 31, 2005. Approximately 274 of the employees at December 31, 2006, were represented by unions for purposes of collective bargaining compared to 277 employees at December 31, 2005. The current collective bargaining agreements with various union-represented employees are identified below:
On November 17, 2006 the National Labor Relations Board certified the results of a union representation election involving 3 Hotflame clerical employees. As a result, the Company is obligated to bargain in good faith with the union representing these employees to attempt to reach agreement on a collective bargaining agreement covering the employees. The collective bargaining agreement covering other Hotflame employees expired on February 28, 2007. The Company and union are discussing the extension of this agreement and related representational matters. The Company expects to engage in negotiations with other collective bargaining representatives of employees as the expiration dates for those agreements approach.
The Company maintains a website on the Internet at address http://www.semcoenergy.com. The Company makes available free of charge, on or through its website, its proxy statements, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (“SEC”). This reference to the Company’s Internet address shall not, under any circumstances, be deemed to
incorporate the information available at such Internet address into this Form 10-K or other SEC filings. The information available at the Company’s Internet address is not part of this Form 10-K or any other report filed by the Company with the SEC. The public may read and copy any documents the Company files at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The Company’s SEC filings can also be obtained on the SEC’s website on the Internet at address http://www.sec.gov.
Item 1A.
Item 1A.
Risk Factors
Investing in the Company involves a number of risks. Investors should carefully consider all of the information contained in this annual report on Form 10-K, as well as the other filings of the Company with the SEC, including the risk factors set forth below, before making an investment in the Company. Described below are some of the risk factors currently known to the Company which make an investment in the Company speculative or risky. The Company may encounter risks in addition to those described below. Investors may lose all or part of their investment in the Company.
Risks Relating to the Share Exchange
The Company cannot make any assurances that the proposed Share Exchange will be consummated.
On February 22, 2007, the Company announced that it had entered into an Exchange Agreement with Cap Rock to acquire each issued and outstanding share of the Company’s Common Stock and Preferred Stock in an all-cash transaction. Consummation of the proposed Share Exchange is not subject to a financing condition, but is subject to various other conditions, including approval of the Share Exchange by the holders of the Company’s Common Stock, approval by the RCA, expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and satisfaction of other customary closing conditions. There is no assurance that all of the various conditions will be satisfied.
Failure to complete the Share Exchange would result in the incurrence of costs, the amounts of which could adversely impact the Company’s future business and financial results.
If the proposed Share Exchange is not completed for any reason, the Company will be subject to numerous expenses, including the following:
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being required, under certain circumstances, to pay a termination fee of $15.5 million and reimburse Cap Rock for up to $2 million in out-of-pocket expenses;
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In the alternative, in certain limited circumstances, the Company may be required to pay Cap Rock a termination fee of $7.5 million and reimburse Cap Rock for up to $3 million in out-of-pocket expenses;
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having incurred certain costs relating to the proposed Share Exchange that are payable whether or not the Share Exchange is completed, including legal, accounting, financial advisor and printing fees; and
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having had management focused on completing the proposed Share Exchange, instead of on pursuing another business strategy, including acquisition or investment opportunities that could have been beneficial to the Company.
If the proposed Share Exchange is not completed, as a result of these and other factors, the Company’s business, financial results and financial condition could be adversely affected.
The Company may not be able to attract or retain key management employees and others.
The announcement of the Share Exchange may have a negative impact on the Company’s ability to attract and retain key management and attract and maintain third-party relationships. Any such events could have a material negative impact on the Company’s results of operations and financial condition.
The Company’s Common Stock price and business prospects may be adversely affected if the Share Exchange is not completed.
If the Share Exchange is not completed, the trading price of the Common Stock may decline, to the extent that the current market prices reflect a market assumption that the Share Exchange will be completed. In addition, the Company’s businesses and operations may be harmed to the extent that third parties believe that the Company cannot effectively operate in the marketplace on a stand-alone basis, or there is management or employee uncertainty surrounding the future direction or strategy of the Company on a stand-alone basis. Management’s attention may be diverted from conducting the day to day business of the Company, and the Company may lose key employees and ongoing business and prospects, as well as relationships with customers and other third parties as a result of these uncertainties. The Company may not be able to take advantage of alternative business opportunities or effectively respond to competitive pressures.
The restrictive covenants of the Exchange Agreement have placed, and will continue to place, significant restrictions on the Company’s business operations until the completion of the Share Exchange.
Pursuant to the Exchange Agreement, until the completion of the Share Exchange, the Company is required to conduct its business in the usual, regular and ordinary course in substantially the same manner as previously conducted and to use commercially reasonable efforts to preserve intact its current business organization and to maintain its relationships with customers, employees, regulatory authorities, suppliers, licensors, licensees and distributors that, in each case, are material to the business of the Company and others having material business dealings with them, consistent with past practice. In addition, the Company is not, among other things, permitted to do or, agree to do, any of the following, except in limited circumstances, without the prior written consent of Cap Rock:
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make certain dividends or distributions on any of its capital stock, split, combine or reclassify its capital stock or issue shares of capital stock;
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amend its Articles of Incorporation or Bylaws;
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acquire or agree to acquire any business or assets that would be material, individually or in the aggregate, to the Company and its subsidiaries, taken as a whole;
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make any change in accounting methods, principles or practices materially affecting the reported consolidated assets, liabilities or results of operations of the Company, except insofar as may be required by a change in GAAP or the interpretation thereof;
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sell, lease (as lessor), license or otherwise dispose of outside the ordinary course of business consistent with past practice, or subject to any lien any properties or assets;
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incur certain indebtedness or guarantee any such indebtedness of another person, issue or sell any debt securities or warrants or other rights to acquire any debt securities of the Company; and
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make or agree to make any new capital expenditure or expenditures that in the aggregate, are in excess of $43.7 million in 2007 and $44.0 million in 2008.
These restrictions could prevent the Company from pursuing attractive business opportunities that may arise prior to the completion of the Share Exchange.
Risks Relating to the Company’s Operations
The Company’s Gas Distribution Business is subject to rate regulation, and certain actions of these regulatory bodies may reduce the Company’s revenues, earnings and cash flow.
The Company is currently regulated by the MPSC and the CCBC in Michigan and the RCA in Alaska. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures and standards of service.
With regard to regulation by the MPSC and the CCBC, in January 2007 and February 2005, respectively, the Company entered into settlements which, upon approval, authorized base rate increases for customers in these
regulatory jurisdictions. As part of the settlement agreement with the MPSC, the Company has agreed not to request a further base rate increase for customers whose rates are currently set by the MPSC until after January 1, 2008. Also, with certain exceptions, the Company agreed not to request a further base rate increase for customers whose rates are set by the CCBC to be effective before April 1, 2008. The Company and the CCBC filed a joint application with the MPSC in May 2006, asking that the MPSC assume jurisdiction over the areas currently regulated by the CCBC. The joint application asked the MPSC to approve the CCBC tariff, rates, charges and conditions of service that are currently in effect. In October 2006, the Company and the CCBC submitted an amended joint application to address certain rate and procedural issues, including the establishment of an MPSC-approved GCR-type rate and tariff for customers in the service area now regulated by the CCBC. The Company believes that this proposed jurisdictional change will not have a material impact on the natural gas rates the Company charges in its CCBC service area, but it cannot assure that any change in jurisdiction will not affect the rates it charges or other aspects of the terms and conditions of service. With regard to regulation by the RCA, in June 2005, the RCA issued an order that, among other things, requires ENSTAR and APC to file a depreciation study of their Alaska utility plant by June 1, 2007 (as of December 31, 2006), and a revenue requirement and cost-of-service study (including rate design data) with the RCA by June 6, 2008 (using a test year ended December 31, 2007).
Approximately 98% of the Company’s 2006 consolidated operating revenues were generated by its regulated Gas Distribution Business. While the Company currently has settlements with the MPSC and the CCBC setting base rates in these jurisdictions, there is no guarantee that the Company would prevail in seeking rate increases in future base rate cases. The Company also has no guarantee that it will be successful in its gas cost recovery cases filed periodically with various regulatory bodies. The possibility of a rate decrease, the failure to grant any requested rate increase, cost disallowances, the precise timing of any rate increase, decrease or any other action by the regulators, may reduce the Company’s revenues, earnings and cash flow.
The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact the Company’s liquidity and earnings.
One component of the regulation of the Company’s rates are mechanisms to recover the cost of purchasing natural gas. In general, the costs of natural gas purchased for customers are recovered on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. The recovery of these gas costs is accomplished through regulatory body-approved GCR pricing mechanisms whereby customer rates are periodically adjusted for increases and decreases in the cost of gas purchased by the Company for sale to its customers. Under the GCR pricing mechanisms, the gas commodity charge portion of gas rates charged to customers (which is also referred to as the “GCR rate”) for the Michigan service areas regulated by the MPSC may be adjusted upward on a quarterly basis and downward on a monthly basis if actual natural gas costs incurred by the Company are significantly different than the prices set in the MPSC-approved GCR plan. The GCR rate for the Michigan service areas regulated by the CCBC may be adjusted upward or downward on a monthly basis. The GCR rate for Alaska is generally adjusted annually to reflect the estimated cost of gas purchased for the upcoming 12-month GCR period.
Increases in natural gas prices and corresponding increases in GCR rates may contribute, in varying amounts, depending on the way in which these costs are recovered in customer rates in each jurisdiction in which the Company does business, to: (i) increased costs associated with lost and unaccounted for gas; (ii) higher customer bad debt expense for uncollectible accounts; (iii) higher working capital requirements; and (iv) reduced sales volumes and related margins due to lower customer consumption.
Volatility in the price of natural gas could result in large industrial customers switching to alternative energy sources or shifting production to facilities outside the Company’s service area, which could reduce revenues, earnings and cash flow.
The market price of alternative energy sources such as coal, electricity, oil and steam is the primary competitive factor affecting the demand for the Company’s gas transportation services. Certain large industrial customers have, or may acquire, the capacity to be able to use one or more alternative energy sources or shift production to facilities outside the Company’s service area if the price of Company-provided natural gas and delivery services increases significantly compared to prices charged for such services elsewhere. Natural gas has typically been less expensive than these alternative energy sources. However, generally over the past three years and
recently in a more significant way, natural gas prices have been higher and more volatile, making some of these alternative energy sources more economical or, for other reasons, more attractive than natural gas. During this period, certain of the Company’s large Michigan industrial customers have periodically switched to alternative energy sources.
To reduce the possibility of fuel-switching or production-shifting by industrial customers, the Company offers flexible contract terms and additional services, such as gas storage and balancing. Partially offsetting the impact of this price sensitivity among certain large industrial customers has been the use of natural gas to reduce emissions from their plants. The Company cannot predict the future trend of natural gas prices with certainty; nor can the Company make any assurances that the impact of environmental legislation or any special services the Company offers will outweigh the negative effects of natural gas price increases and volatility. Should these customers decide to use another form of energy or shift production elsewhere, the Company’s revenues, earnings and cash flow would be adversely affected.
The Company’s liquidity and earnings could be adversely affected by the MPSC’s disallowance of costs after retrospective reviews of the Company’s gas procurement practices.
In the Company’s gas distribution area regulated by the MPSC, the Company’s gas procurement practices are subject to an annual retrospective MPSC review. If costs are disallowed in this review process, such costs would be expensed in the cost of gas but would not be recovered by the Company in rates. MPSC reviews of the Company’s gas procurement practices creates the potential for the disallowance of the Company’s recovery, through its GCR rates, of some of its costs of purchasing gas. Such disallowances could affect the Company’s liquidity and earnings.
The Company’s earnings and cash flow are sensitive to decreases in customer consumption resulting from warmer than normal temperatures and customer conservation.
The Company’s gas sales revenue is generated primarily through the sale and delivery of natural gas to residential and commercial customers who use natural gas mainly for space heating. Consequently, temperatures have a significant impact on sales and revenues. Given the impact of weather on the Company’s Gas Distribution Business, this segment is a seasonal business. Most of the Company’s gas sales revenue is generated in the first and fourth quarters of the calendar year and the Company typically experiences losses in the non-heating season, which occurs in the second and third fiscal quarters of the year. In addition, conservation has continued to reduce demand for natural gas from the Company’s customers.
Warmer than normal temperatures and conservation over the last several years have adversely affected the earnings and cash flow of the Gas Distribution Business, which has accounted for approximately 98% of consolidated operating revenues for the last three fiscal years. In the Company’s Michigan service area, the temperature was approximately 11.8%, 0.1% and 0.3% warmer than normal during 2006, 2005 and 2004, respectively. The temperature was approximately 6.4% colder than normal in the Alaska service area during 2006 and 5.7% and 6.0% warmer than normal in the Alaska service area during 2005 and 2004, respectively. In addition, the average annual natural gas consumption of customers has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances, and customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy savings devices and techniques. A mild winter, as well as continued or increased conservation, in any of the Company’s service areas can have a significant adverse impact on demand for natural gas and, consequently, earnings and cash flow.
The Company’s earnings are substantially dependent on its current customers maintaining a certain level of consumption as well as on customer growth.
Many of the Company’s customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy savings devices and techniques. During the past several years, average annual per customer gas consumption has been decreasing. In addition, increases in natural gas prices appear to have increased conservation efforts by customers. The Company expects this conservation trend to continue as an era of higher and more volatile natural gas prices influences customer
consumption. In the MPSC order issued on January 9, 2007, residential base rates in the service area regulated by the MPSC were set using a lower annual use per residential customer billing determinant, which recognizes that residential customer consumption has been steadily declining and sets base rates using an annual volume of gas consumption per customer that may be reasonably expected to be sold in a year with normal weather under current consumption patterns. Continued and significant declines in consumption by the Company’s current customers, without adjustments to its rates or rate design, may negatively impact the Company’s earnings.
In addition, the Company’s earnings growth is substantially dependent on customer growth. The average number of gas sales customers in Michigan and Alaska combined (excluding customers acquired in the acquisition of Peninsular Gas) has increased by an average of 1.8% annually during the past three years. The average number of customers at SEMCO Gas (excluding customers acquired in the acquisition of Peninsular Gas) has increased by an average of approximately 1.1% annually during the past three years (0.6% in 2006), and the average number of customers at ENSTAR has increased by an average of approximately 3.3% annually during the past three years (3.2% in 2006). If the Company is unable to achieve sufficient customer growth within its existing service territories or add additional customers by expanding service territories, the Company’s earnings growth may be negatively impacted.
The Company’s customers may be able to acquire natural gas without using the Company’s distribution system, which would reduce revenues and earnings.
There is potential risk that Michigan industrial customers and electric generating plants located in close proximity to interstate natural gas pipelines will bypass the Company’s distribution system and connect directly to such pipelines. Such bypass efforts would reduce the Company’s revenues and earnings. From time to time, customers raise the issue of bypass and the Company attempts to address their concerns. The Company can make no assurances that its customers will not bypass the Company’s distribution system or that the Company could successfully retain such customers.
Declining production from the Cook Inlet gas fields may result in potential deliverability problems in ENSTAR’s service area.
ENSTAR’s gas distribution system, including the APC pipeline system, is not linked to major interstate and intrastate pipelines or natural gas supplies in the United States or in Canada. As a result, ENSTAR procures natural gas supplies under long-term RCA-approved contracts from producers in and near the Cook Inlet area. Production from the Cook Inlet area gas fields is declining and new discoveries have been modest. As of January 1, 2006, the Cook Inlet area had approximately 1.6 Tcf of total proven natural gas reserves according to the most recently available information contained in the Alaska Department of Natural Resources Division of Oil and Gas 2006 Annual Report. Based on the Department’s reported 2005 net production of 209 Bcf, there was a reserve life at January 1, 2006, of approximately 8 years in the Cook Inlet area, although shortages of daily deliverability have occurred resulting in curtailment of some industrial loads (which were not served by ENSTAR) during cold weather periods. There is ongoing exploration for natural gas in the Cook Inlet area, including producers that have supply contracts with ENSTAR. The United States Geological Survey and Minerals Management Service has estimated that the Cook Inlet area contains another approximately 2.3 Tcf of undiscovered natural gas, but there are no assurances that any of this natural gas will be discovered and, if discovered, can be produced economically and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.
Activity continues with respect to the possible construction of a natural gas pipeline that would extend from Alaska’s North Slope, through Alaska and Canada, to the lower 48 states of the United States. Assuming this or another pipeline is built, the flow of natural gas through it could not be expected to begin before the middle of the next decade, at the earliest. The Company can provide no assurances with respect to the construction of this or another pipeline, when such a pipeline would be put in service, or whether natural gas supplies transported by such a pipeline would be available to ENSTAR customers and secured by ENSTAR on terms and conditions that would be acceptable to the RCA.
Changes in the regulatory environment and events in the energy markets that are beyond the Company’s control may reduce the Company’s earnings and limit its access to capital markets.
The Company’s Gas Distribution Business is subject to regulation by various federal, state and local regulators as well as the actions of federal, state and local legislators. As a result of the energy crisis in California during 2000 and 2001, the recent volatility of natural gas prices in North America, the bankruptcy filings by certain energy companies, investigations by governmental authorities into energy trading activities, the collapse in market values of energy companies and the downgrading by rating agencies of a large number of companies in the energy sector, companies in regulated and unregulated energy businesses have generally been under increased scrutiny by federal, state and local regulators, participants in the capital markets and debt rating agencies. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that could impact the way the Company is required to record revenues, expenses, assets and liabilities. The Company cannot predict or control what effect these types of events, or future actions of regulatory agencies or others in response to such events, may have on its earnings or access to the capital markets.
The Company may be required to recognize additional impairment charges which would reduce its earnings.
Pursuant to generally accepted accounting principles, the Company is required to perform impairment tests on its goodwill balance annually or at any time when events occur that could impact the value of its business segments.
The 2006 annual goodwill impairment test for the Company’s propane business was performed during the third quarter of 2006 and showed that there was no impairment of goodwill. The 2006 annual impairment test for the Company’s Gas Distribution Business was performed during the fourth quarter of 2006 and showed that there was no impairment of goodwill. There were no adverse changes in the carrying amount of goodwill for 2006.
The 2005 annual goodwill impairment test for the Company’s propane business was performed during the third quarter of 2005 and showed that there was no impairment of goodwill. The 2005 annual impairment test for the Company’s Gas Distribution Business was performed during the fourth quarter of 2005 and showed that there was no impairment of goodwill. There were no adverse changes in the carrying amount of goodwill for 2005.
During the fourth quarter of 2004, it was determined that all of the goodwill associated with the Company’s IT services business ($0.2 million) was impaired. The $0.2 million before-tax charge for impairment of goodwill is reflected in the Company’s Consolidated Statements of Operations for the year ended December 31, 2004, in operating expenses.
The Company’s determination of whether an impairment has occurred is based on an estimate of discounted cash flows attributable to reporting units that have goodwill. The Company must make long-term forecasts of future revenues, expenses and capital expenditures related to the reporting unit in order to make the estimate of discounted cash flows. These forecasts require assumptions about future demand, future market conditions, regulatory developments and other factors. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period that could substantially reduce the Company’s earnings in a period of such change, but not have any impact on its cash flow.
The Company’s ability to use net operating loss carry-forwards may be impaired.
As of December 31, 2006, the Company had available approximately $84 million of net operating losses, or NOLs, with which to offset federal income taxes with respect to the Company’s future taxable income. In 2004, the Company underwent an “ownership change” for purposes of Section 382 of the Internal Revenue Code of 1986, as amended. In general, an ownership change occurs whenever there is a more than 50% change in the ownership of the stock of a corporation, taking into account all cumulative changes in ownership over the preceding three years. As a result of the ownership change, the Company’s ability to use approximately $74 million of its total NOLs in the future is limited. However, the Company believes that, based on the size of the limitation and projections of future taxable income, the Company should be able to utilize all of the NOLs before they expire.
The issuance of additional shares of the Company’s capital stock could ultimately trigger another ownership change that could further limit the Company’s ability to use such NOLs. While the Company’s March 2005 issuance
of Preferred Stock and the August 2005 Common Stock offering did not trigger such an ownership change, those offerings when coupled with future capital stock offerings and changes in the ownership of the Company’s capital stock (some of which will be beyond the Company’s control) will probably lead to a future ownership change. Any such future ownership change could result in the imposition of lower limits on the Company’s utilization of the NOLs to offset future taxable income as well as the Company’s ability to use certain losses and tax credits. The magnitude of such limitations and their effect on the Company is difficult to assess and will depend in part on the value of the Company at the time of any such ownership change and prevailing interest rates at that time.
The Company’s operations and business are subject to environmental laws and regulations that may increase the Company’s cost of operations, impact or limit the Company’s business plans or expose the Company to environmental liabilities.
The Company’s operations and business are subject to environmental laws and regulations that relate to the environment and health and safety, including those that impose liability for the costs of investigation and remediation, and for damage to natural resources from, past spills, waste disposal on- and off-site and other releases of hazardous materials or regulated substances. In particular, under applicable environmental requirements, the Company may be responsible for the investigation and remediation of environmental conditions at currently owned or leased sites, as well as formerly owned, leased, operated or used sites. The Company may be subject to associated liabilities, including liabilities resulting from lawsuits brought by private litigants, related to the operations of the Company’s facilities or the land on which such facilities are located, regardless or whether the Company leases or owns the facility, and regardless of whether such environmental conditions were created by the Company or by a prior owner or tenant, or by a third-party or a neighboring facility whose operations may have affected the Company’s facility or land.
Given the nature of the past operations conducted by the Company and others at the Company’s properties, there can be no assurance that all potential instances of soil or groundwater contamination have been identified, even for those properties where environmental site assessments or other investigations have been or will be conducted. Changes in existing laws or policies or their enforcement, future spills or accidents or the discovery of currently unknown contamination may give rise to environmental liabilities which may be material. Based upon the information presently available to the Company, the Company expects to incur costs associated with investigatory and remedial actions at seven of its Michigan sites that formerly housed manufactured gas plant operations. Based on investigational work performed to date at three of these sites, the Company’s Consolidated Statements of Financial Position include an accrual and a corresponding regulatory asset in the amount of $1.6 million at December 31, 2006, for estimated environmental investigation and remediation costs that it believes are probable at these three sites. The accrual of $1.6 million represents what the Company believes is probable and reasonably estimable. However, the Company also believes that it is reasonably possible that there could be up to an estimated $18.5 million of environmental investigation and remediation costs for these three sites, in addition to the $1.6 million already accrued.
The Company has done less investigational and remediation work at the remaining four sites but has met all applicable MDEQ requirements. The Company believes that further investigation and any remediation of environmental conditions at these sites may be the obligation of other potentially responsible parties. It is reasonably possible that the Company’s current estimate concerning costs likely to be incurred in connection with the investigation and any remediation of conditions at these four sites may change in the future as new information becomes available and circumstances change, including the Company’s further evaluation of the obligations of other potentially responsible parties for these costs. If this were to occur, the Company’s liability with respect to costs at these four sites could be material.
In accordance with an MPSC accounting order, the payment by the Company of environmental assessment and remediation costs associated with certain manufactured gas plant sites and other environmental expenses are deferred and amortized over ten years. Rate recognition of the related amortization expense does not begin until the costs are subject to review in a base rate case. To the extent not fully recoverable from customers through regulatory proceedings or from insurance or others, these costs would reduce the Company’s earnings and results of operations.
Compliance with the requirements and terms and conditions of the environmental licenses, permits and other approvals that are required for the operation of the Company’s business may cause the Company to incur substantial capital costs and operating expenses and may impose restrictions or limitations on the operation of the Company’s business, all of which could be substantial. Environmental, health and safety regulations may also require the Company to install new or updated pollution control equipment, modify its operations or perform other corrective actions at its facilities. Existing environmental, health and safety laws and regulations may be revised to become more stringent or new laws or regulations may be adopted or become applicable to the Company which may result in increased compliance costs or additional operating restrictions and could reduce the Company’s earnings and harm the Company’s business, particularly if those costs are not fully recoverable from its customers through regulatory proceedings.
Substantial operational risks are involved in operating natural gas distribution, pipeline and storage system and propane distribution businesses, and such operational risks could adversely affect the Company’s revenues, earnings, cash flow and financial condition.
There are substantial risks associated with the operation of natural gas distribution, pipeline and storage system, and propane distribution businesses, such as operational hazards and unforeseen interruptions caused by events beyond the Company’s control. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond the Company’s control. These risks could result in injury or loss of life, property damage, business interruption or environmental pollution, which in turn could lead to substantial financial losses to the Company. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of these risks. Liabilities incurred that were not fully covered by insurance could adversely affect the Company’s earnings, cash flow and financial condition. Additionally, interruptions to the operation of the Company’s gas distribution, pipeline or storage system caused by such an event could reduce revenues generated by the Company and, consequently, earnings and cash flow.
In the event that the Share Exchange or a similar transaction to sell the Company is not consummated, the Company’s ability to grow its businesses will be adversely affected if the Company is not successful in making acquisitions or in integrating the acquisitions it makes.
In the event that the Share Exchange or a similar transaction to sell the Company is not consummated, the Company would likely continue with its long-term strategy to grow through acquisitions. There is growing and significant competition for acquisitions in the U.S. natural gas industry, and the Company believes that there are numerous potential acquisition candidates, some of which represent opportunities that would be material to the Company. The Company cannot assure that it will find attractive acquisition candidates in the future, that it will be able to acquire such candidates on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance acquisitions will not impair its capitalization. The Company is currently governed by an amended and restated three-year unsecured revolving bank credit facility for $120 million, which expires on September 15, 2008 (the “Bank Credit Agreement”), which also limits the consideration the Company may pay in connection with any one acquisition to $50 million and in connection with all acquisitions occurring after September 15, 2005, to $150 million. Under the Bank Credit Agreement, these limitations will not apply to acquisitions occurring after the Company reaches certain investment grade debt ratings.
In addition, the restructuring of the energy markets in the U.S. and internationally, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for, and competition from, well-capitalized existing competitors as well as new entrants to the markets, which may affect the Company’s ability to achieve this aspect of its business strategy.
To the extent the Company is successful in making acquisitions, such acquisitions can involve a number of risks, including the assumption of material liabilities, the terms and conditions of any state or federal regulatory approvals required for the acquisitions, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices, as well as in the assimilation of broad and geographically
dispersed personnel and operations. The failure to make and integrate acquisitions successfully could have an adverse effect on the Company’s ability to grow its business.
Earnings and cash flow may be adversely affected by downturns in the economy.
The Company’s operations are affected by the conditions and overall strength of the national, regional and local economies, which impact the amount of residential, industrial and commercial growth and actual gas consumption in the Company’s service territories. Many of the Company’s commercial and industrial customers use natural gas in the production of their products. During economic downturns, these customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of natural gas they require for production. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts often increases. These factors may reduce earnings and cash flow.
The Company’s debt indentures and Bank Credit Agreement contain restrictive covenants that may reduce the Company’s flexibility, and adversely affect its business, earnings, cash flow, liquidity and financial condition.
The terms of the indentures relating to certain of the Company’s currently outstanding debt securities and of the Company’s Bank Credit Agreement impose significant restrictions on the Company’s ability and, in some cases, the ability of the Company’s subsidiaries, to take a number of actions that the Company may otherwise desire to take, including:
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requiring the Company to dedicate a substantial portion of its cash flow from operations to the payment of principal and interest on the Company’s indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities;
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requiring the Company to meet certain financial tests, which may affect the Company’s flexibility in planning for, or reacting to, changes in the Company’s business and the industries in which the Company operates;
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limiting the Company’s ability to sell assets, make investments or acquire assets of, or merge or consolidate with, other companies;
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limiting the Company’s ability to repurchase or redeem its stock or enter into transactions with its stockholders or affiliates; and
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limiting the Company’s ability to grant liens, incur additional indebtedness or contingent obligations or obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other activities.
These covenants place constraints on the Company’s business and may adversely affect its growth, business, earnings, cash flow, liquidity and financial condition. The Company’s failure to comply with any of the financial covenants in its Bank Credit Agreement may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the Company’s Bank Credit Agreement, the indentures governing its outstanding debt issuances, various lines of credit that the Company has entered into in the last year or other agreements the Company may enter into from time to time that contain cross-acceleration or cross-default provisions. In such a case, there can be no assurance that the Company would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on its business, earnings, cash flow, liquidity and financial condition.
Adverse changes in the Company’s credit ratings may limit the Company’s access to capital, increase the Company’s cost of capital, increase the cost of maintaining certain contractual relationships or otherwise have a material adverse effect on the Company’s business, earnings, cash flow, liquidity and financial condition.
In March 2003, Moody’s Investors Service, Inc. reduced the credit rating on the Company’s senior unsecured debt from Baa3 to Ba2. Since June 2003, Standard & Poor’s Ratings Group has lowered the Company’s corporate credit rating from BBB- to BB-. These downgrades have required the Company to pay higher interest rates for financing, increasing the Company’s cost of capital. Any additional downgrades could further increase the Company’s capital costs (including the rates for borrowing under the Company’s Bank Credit Agreement) and limit its pool of potential investors and funding sources, possibly increasing the costs of operations or requiring the Company to use a higher percentage of its available borrowing capacity for ordinary course purposes.
In addition, on February 23, 2007, Moody’s Investors Service, Inc. changed the Company’s ratings outlook to “Developing” from “Stable” upon the announcement of the Company’s entry into the Exchange Agreement.
Further credit downgrades or ratings outlook changes could also negatively affect the terms on which the Company can purchase gas and pipeline capacity. As a result of the Company’s non-investment grade credit rating noted above, the interstate pipelines the Company utilizes require prepayment for their services. In addition, certain of the Company’s gas suppliers may require the Company to prepay or provide letters of credit for gas purchases over and above the levels of credit they may have extended to the Company. The Company can provide no assurance that suppliers will not impose additional requirements or restrictions on the conduct of the Company’s business.
The Company can provide no assurance that any of its current ratings or ratings outlook 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. Any downgrade or other adverse action could adversely affect the Company’s business, earnings, cash flow, liquidity and financial condition.
The Company’s substantial indebtedness may limit its ability to borrow additional funds at all, or on reasonable terms, limit its growth and diminish its ability to respond to changing business and economic conditions and, thereby, may adversely affect its business, earnings, cash flow, liquidity and financial condition.
The Company’s business is capital intensive and the Company has significant amounts of debt. At December 31, 2006, the Company had total short and long-term debt of $504.0 million. The Company’s substantial debt may adversely affect its business, earnings, cash flow, liquidity and financial condition. For example, the Company’s substantial debt may, among other things:
•
limit the Company’s ability to borrow additional funds;
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increase the cost of any future debt that the Company incurs;
•
reduce cash flow from operations available for working capital, capital expenditures and other general corporate purposes;
•
limit the Company’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates;
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place the Company at a competitive disadvantage as compared to the Company’s competitors that are less highly leveraged;
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result in a downgrade in the Company’s credit ratings; or
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diminish the Company’s ability to successfully withstand a downturn in its business or the economy generally.
The Company’s ability to meet its debt service obligations and to reduce its total indebtedness will depend upon its future performance, which will be subject to weather, general economic conditions, industry cycles and financial, business and other factors affecting the Company’s operations, many of which are beyond the Company’s
control. No assurance can be provided that the Company’s business will generate sufficient cash flow from operations or that future borrowings will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness or to fund its other liquidity needs. The Company may need to refinance all or a portion of its indebtedness on or before maturity. No assurance can be provided that the Company will be able to refinance any of its indebtedness, including its Bank Credit Agreement, its various line of credit and its existing debt and debt securities, on commercially reasonable terms or at all.
Despite the Company’s substantial indebtedness, the Company may still be able to incur more debt, which could further exacerbate the risks associated with its substantial debt.
Although the Company is presently limited in incurring additional indebtedness, the Company may be able to incur additional debt in the future. Restrictions applicable to the Company on the incurrence of additional debt contained in its indentures, Bank Credit Agreement governing the Company’s existing debt and the Exchange Agreement are subject to a number of qualifications and exceptions that allow the Company to incur additional debt. An increase in the amount of indebtedness may negatively affect the Company’s capital structure and credit ratings. If new debt is added to the Company’s current debt levels, the risks that the Company now faces could intensify.
The Company is vulnerable to interest rate risk with respect to its debt which could lead to an increase in interest expense and a corresponding decrease in earnings and cash flow.
The Company’s ability to finance capital expenditures and to refinance its maturing debt will depend in part on conditions in the capital markets, including interest rates. The Company’s cost of borrowing under its Bank Credit Agreement is also dependent on interest rates. In addition, in order to maintain the Company’s desired mix of fixed-rate and variable-rate debt, the Company may use interest rate swap agreements and exchange fixed and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. No assurance can be provided that the Company will be successful in structuring such swap agreements to manage its risks effectively. If the Company is unable to do so, its earnings and cash flow may be reduced.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Item 2.
Properties
Gas Distribution Business Segment
The natural gas transmission and delivery system of SEMCO Gas included approximately 131 miles of gas transmission pipelines and 5,631 miles of gas distribution mains at December 31, 2006. The pipelines and mains are located throughout the southern half of Michigan’s lower peninsula (centered in and around the cities of Albion, Battle Creek, Holland, Niles, Port Huron and Three Rivers) and also in the central and western areas of Michigan’s Upper Peninsula. At December 31, 2006, ENSTAR’s natural gas delivery system (including APC’s natural gas transmission system) included approximately 348 miles of gas transmission pipelines and 2,735 miles of gas distribution mains. ENSTAR’s pipelines and mains are located in Anchorage and the Cook Inlet area.
The distribution mains of the Gas Distribution Business are, for the most part, located on or under public streets, alleys, highways and other public places, or on private property not owned by the Company with permission or consent, except to an inconsequential extent, of the individual property owners. The distribution mains located on or under public streets, alleys, highways and other public places were installed under valid rights and consents granted by appropriate local authorities.
The Gas Distribution Business owns underground gas storage facilities in eight salt caverns and three gas reservoirs, together with related measuring, compressor and transmission facilities. The storage facilities are all located in Michigan. The aggregate working capacity of the storage system is approximately 5.1 Bcf.
The Gas Distribution Business also owns meters and service lines, gas regulating and metering stations, garages, warehouses and other buildings necessary and useful in conducting its business. In addition, the Gas Distribution Business leases a significant portion of its transportation equipment and certain buildings.
Corporate and Other
The principal properties of this segment include interests and operations in IT services, propane distribution, natural gas transmission pipelines, an underground gas storage system and general corporate facilities supporting these operations.
The properties of the Company’s IT services business consist of a building, office equipment, telecommunications equipment and computer equipment. The building is located in Marysville, Michigan, and houses this IT equipment.
The property of the propane distribution operation consists primarily of pressurized propane storage tanks used by customers to store propane purchased from the Company and trucks for transporting propane. The Company also owns large propane storage tanks that allow the Company to store up to 258,000 gallons of propane inventory. The propane distribution property is located in Michigan’s Upper Peninsula and northeast Wisconsin.
The Company owns a 50% equity interest in the ERGSS. The Company’s equity investment in the ERGSS totaled approximately $8.6 million at December 31, 2006. This natural gas storage system, located near Eaton Rapids, Michigan, became operational in March 1990 and consists of approximately 12.8 Bcf of underground storage capacity. The Gas Distribution Business leases 6.5 Bcf of the capacity under a long-term contract that expires April 1, 2010. In addition, SEMCO Energy Ventures, Inc., one of the Company’s non-regulated subsidiaries, also contracted to lease 425 MMcf of interruptible capacity from ERGSS for the period from April 1, 2006, to March 31, 2007.
The following table sets forth the natural gas pipeline operations wholly or partially owned by the Company, the total net property of each system, and the Company’s ownership percentage and net property in each system at December 31, 2006:
The Litchfield Lateral is a 31-mile pipeline located in southwest Michigan. This pipeline, which is leased entirely to ANR Pipeline Company, links the ERGSS with interstate pipeline supplies. The Greenwood Pipeline is a 17-mile pipeline that connects an interstate pipeline with the DTE Energy Greenwood Power Plant located near Port Huron, Michigan. The pipeline provides transportation services to the Greenwood Power Plant and also supplies customers of the Gas Distribution Business in the service area north of Port Huron, Michigan. The Eaton Rapids Pipeline is a 37-mile pipeline that delivers gas from the ERGSS to the Gas Distribution Business’ systems in Battle Creek and Albion, Michigan, and to an ethanol plant located near Albion, Michigan.
The Company’s corporate division is a cost center rather than a business segment. The properties of the corporate division primarily include leasehold improvements, office furniture, office equipment, computers and computer systems. These properties are located in a leased office building in Port Huron, Michigan (which houses the Company’s headquarters), and leased satellite office space in Troy, Michigan.
Item 3.
Item 3.
Legal Proceedings
In the normal course of business, the Company may be a party to lawsuits and administrative proceedings before various courts and government agencies. The Company also may be involved in private dispute resolution proceedings. These lawsuits and proceedings may involve personal injury, property damage, contractual issues and other matters (including alleged violations of federal, state and local laws, rules, regulations and orders). Management cannot predict the outcome or timing of any pending or threatened litigation or of actual or possible
claims. Except as otherwise stated, management believes resulting liabilities, if any, will not have a material adverse impact upon the Company’s financial position, results of operations, or cash flows.
In September 2002, the Company agreed to relocate its headquarters to Port Huron, Michigan, and leased part of a new office building in Port Huron from Acheson Ventures LLC (“Acheson”). As part of the transaction, Acheson agreed to sublease office space occupied by the Company in Farmington Hills, Michigan, and, beginning in February 2005, began to pay the Company’s Farmington Hills lease costs (approximately $36,000 per month until March 31, 2011, when the Farmington Hills lease expires), as agreed. In June 2005, Acheson ceased making these payments, ostensibly because the Company had allegedly breached its obligations by maintaining a satellite office in Troy, Michigan, for certain executives who also have offices in the Company’s Port Huron headquarters. The Company has filed an action in Michigan state court, seeking (i) damages for Acheson’s failure to pay the Company’s Farmington Hills lease costs, and (ii) a declaratory judgment that the Company has met its obligations to Acheson. On January 16, 2006, Acheson answered the Company’s complaint, filed counter-claims alleging breach of contract, fraud, and negligent misrepresentation, and sought a change of venue for these proceedings, to Port Huron, Michigan. The Company made filings to answer Acheson’s counter-claims, denying any liability to Acheson and opposing a change of venue. The court subsequently ruled that venue for this case was properly laid in Oakland County, Michigan. Pre-trial activities in this case, including Acheson’s motion renewing its venue change request, are underway. The court ruled on February 21, 2007, that the venue was proper in Port Huron, Michigan, essentially overturning its earlier venue ruling. The Company expects to ask the court to reconsider this recent venue ruling.
To mitigate its damages, the Company paid the Farmington Hills lease costs and marketed the space to prospective subtenants, since the time Acheson ceased making the lease payments. In March 2006, the Company entered into a sublease with a subtenant that will pay a portion of these lease costs. As a result of this sublease agreement, the Company recorded a $1.2 million pre-tax loss in the first quarter of 2006 representing the difference between the present value of the amount it expects to receive from the subtenant and the present value of the remaining amount owed to the landlord under the terms of the lease.
In April 2006, Aurora Gas gave the Company notice of the suspension of gas deliveries, effective October 1, 2006, and subsequently suspended deliveries, to APC (which, in turn, are delivered to the Company’s ENSTAR division for resale to its customers in Alaska) under the Moquawkie Contract. Aurora Gas asserted that it was permitted to take these actions because production has become “Not Economic,” as that term is defined in the Moquawkie Contract. The Company disagrees with Aurora Gas’ contentions, and attempts to resolve this matter informally were unsuccessful. The Company filed suit against Aurora Gas and an affiliate in Alaska state court asserting, among other things, a breach of contract claim. Aurora Gas has defended against the Company’s claims in this lawsuit by insisting upon its right to suspend gas deliveries. For further information concerning this dispute with Aurora Gas and related rate recovery implications, refer to Note 2 - Regulatory Matters.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2006.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’s Common Stock began trading on the NYSE on January 6, 2000, with the trading symbol “SEN.” The table below shows the reported high and low sales prices of the Company’s Common Stock during 2006 and 2005, as reported on the NYSE.
At February 28, 2007, the closing price of the Company’s Common Stock was $7.69 per share and the Company had 35,488,164 shares of Common Stock outstanding and had 7,436 registered holders of its Common Stock. The Company did not pay any cash dividends on its Common Stock during 2006 and 2005. The Company stopped paying a cash dividend in 2004 with the objective of retaining cash in order to supplement free cash flow, strengthen the Company’s balance sheet, enhance financial flexibility and to be better positioned to grow the Company’s Gas Distribution Business in the future.
For information relating to compensation plans under which equity securities of the Company are authorized for issuance, see Item 12 of this Form 10-K.
During the fourth quarter of 2006, the Company issued an aggregate of three shares of its Common Stock pursuant to its Employee Stock Gift Program in reliance on exemptions from registration under the Securities Act of 1933, as amended, including Section 4(2) thereof.
Item 6.
Item 6.
Selected Financial Data
The following tables set forth selected financial and operating data. The selected financial data presented below should be read in conjunction with the Company’s Consolidated Financial Statements and the Notes to the Company’s Consolidated Financial Statements in Item 8 of this Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operation
Business Strategy Summary
The Company is primarily a regulated natural gas distribution company with operations in Michigan and Alaska. The Company provides natural gas service to approximately 413,000 customers, with approximately 287,000 customers in Michigan and 126,000 customers in Alaska. Approximately 90% of the Company’s customer base consists of residential customers. The Company’s Gas Distribution Business sells a significant portion of gas to customers for heating purposes and, therefore, is a seasonal business. As a result, earnings are significantly influenced by the weather and concentrated in the first and fourth fiscal quarters of the year. The Company typically experiences net losses during the non-heating season, which takes place in the second and third fiscal quarters of the year. The Company’s business is regulated by the MPSC, CCBC, and RCA.
On February 22, 2007, the Company entered into the Exchange Agreement by and among the Company, Cap Rock and Parent, a direct wholly-owned subsidiary of Cap Rock, under which Parent will acquire all the outstanding Common Stock and Preferred Stock of the Company. For information on this transaction and the terms of the Exchange Agreement, refer to Note 15 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Form 10-K. Consummation of the transaction is not subject to a financing condition, but is subject to various other conditions, including approval of the Share Exchange by the holders of the Company’s Common Stock, approval by the RCA, expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and satisfaction of other customary closing conditions. In addition, the Exchange Agreement contains a “go shop” provision pursuant to which the Company intends to solicit superior acquisition proposals during a period of 35 days following the date of the Exchange Agreement. As a result, much of
Company management’s time during 2007 will be focused on obtaining the required approvals to close the Share Exchange or other related transactions.
In addition, the Company will continue to focus on improving its operating results and financial condition. As part of this effort in 2006, the Company attempted to contain its controllable costs (including capital expenditures and operation and maintenance expenses), and the Company expects to continue these efforts in 2007. The most significant undertaking in 2006 to improve the Company’s operating results was the rate case the Company filed with the MPSC. In addition to seeking a substantial revenue increase, the Company proposed several changes to its rate design in the filing. The MPSC approved a settlement of this case on January 9, 2007, and issued an order for the implementation of the new rates for service rendered on and after January 10, 2007. Under this MPSC-approved settlement, the Company was authorized to collect additional revenues using, for residential customers, a billing determinant that more closely approximates current customer usage on a normalized basis. Refer to Note 2 of the Notes to the Consolidated Financial Statements for additional information regarding the Company’s proposed changes to rate design and the settlement approved by the MPSC.
The MPSC order did not include several changes to rate design proposed by the Company. However, as noted, the order does address the continuing decline in residential customer consumption by changing a key billing element of residential base rates. In an MPSC order issued in the Company’s previous rate case proceeding in March 2005, residential base rates were set using annual customer usage of about 113 Mcf of natural gas. In the MPSC’s January 9, 2007 order, residential base rates were set using annual customer usage of 96 Mcf of natural gas. This significant reduction in the residential billing determinant recognizes that residential customer consumption has been steadily declining and sets base rates using an annual volume of gas consumption per customer that may be reasonably expected to be sold in a year with normal weather under current consumption patterns. In future rate cases in Michigan and Alaska, the Company will continue to assess the need for rate design changes and propose changes that take into consideration the changing business environment in which the Company operates, including trends such as higher and more volatile natural gas prices and declining customer consumption.
With respect to improving the Company’s financial condition, the Company expects to continue to improve its credit quality by reducing its fixed financing charges and lowering its total debt as a percentage of total capital during 2007. This improvement is expected to be achieved by applying free cash flow (after capital expenditures) to debt repayment and through growth in retained earnings.
If the Share Exchange or a similar transaction is not consummated, the Company would likely continue to pursue its long-term strategic plan. This plan would likely include improving the Company’s overall financial structure, with a view to migrate over time to a capital structure that is consistent with that of an investment grade company. This long-term strategic plan also would likely include growth through appropriate acquisitions of, or investments in, local distribution, pipeline, and gas storage businesses and assets.
Summary of Results of Operations
The discussions in this section are summarized and intended to provide an overview of the results of Company operations. In most instances, the items discussed in this summary are covered in greater detail in later sections of Management’s Discussion and Analysis. Any variances in results in this summary are quantified on an after-tax basis. The Company uses an effective income tax rate of 36.9% to estimate these after-tax amounts. All references to earnings or losses per share (“EPS”) in Management’s Discussion and Analysis are on a fully diluted basis. For information related to the calculation of diluted EPS, refer to Note 10 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. The following table summarizes the Company’s operating results for the past three years:
Comparison of 2006 and 2005 results. The Company’s $7.7 million of net income available to common shareholders for 2006 was a $7.5 million improvement over 2005 results. There were a number of offsetting factors that impacted net income available to common shareholders in 2006. The primary factors that improved 2006 results, when compared to 2005, were: (i) a decrease in financing-related costs; (ii) customer growth (particularly in Alaska); (iii) base rate increases in Michigan that became effective in April 2005; and (iv) a decrease in property and other tax expense. The decrease in financing-related costs increased net income for 2006 by approximately $10.6 million, when compared to 2005. An $8.2 million charge associated with the repurchase of the Company’s Convertible Preference Stock (“CPS”) and certain Common Stock Warrants (“Warrants”), which was included in results for 2005, was a significant contributor to the decrease in financing-related costs in 2006. In addition, lower levels of outstanding debt and preferred securities during 2006 also contributed to the decrease in financing-related costs. Customer growth increased net income by approximately $1.5 million, while base rate increases in Michigan increased net income by approximately $1.6 million. However, as noted below, the positive impact of customer growth and rate increases was offset almost entirely by the impact of warmer weather and customer conservation. The decrease in property and other tax expense, which increased net income in 2006 by approximately $0.5 million when compared to 2005, was primarily the result of taxing jurisdictions in Michigan accepting the Company’s settlement offers related to outstanding property tax appeals and refunding certain property taxes.
The primary factors that negatively impacted earnings for 2006, when compared to 2005, were: (i) an increase in operations and maintenance (“O&M”) expense for the Gas Distribution Business; (ii) warmer temperatures and customer conservation; and (iii) the inclusion in 2005 results of $0.5 million of income from discontinued operations. The increase in O&M expense for the Gas Distribution Business, which decreased 2006 net income by approximately $3.6 million when compared to 2005, was due primarily to an increase in employee benefit costs and uncollectible customer accounts (or bad debt expense) and a $0.8 million charge, net of income taxes, associated with the sublease of the Company’s former headquarters. Warmer temperatures and customer conservation reduced 2006 net income by approximately $2.9 million, when compared to 2005. Refer the caption “The Impact of Weather and Energy Conservation” for further information.
Comparison of 2005 and 2004 results. The Company’s $0.2 million of net income available to common shareholders for 2005 was an $8.6 million improvement over 2004 results. There were a number of offsetting factors that impacted net income available to common shareholders. The primary factors that improved 2005 results, when compared to 2004, were: (i) an increase in gas sales margin and other gas distribution revenue; (ii) the absence from 2005 results of expenses associated with the terminated sale of the Company’s APC subsidiary; (iii) changes in results from discontinued operations ($0.5 million of income in 2005 compared to $9.3 million of losses in 2004); and (iv) a decrease in property and other tax expense. The increase in gas sales margin and other gas distribution revenue increased net income by approximately $6.6 million and was attributed in large part to rate increases in Michigan and the addition of new customers, partially offset by a decrease in gas consumption by customers. The expenses included in 2004 results for the Company’s APC subsidiary include costs associated with an arbitration proceeding over the termination of the Company’s sale of the APC subsidiary and a payment by the Company to settle the matter. These APC-related expenses increased the 2004 net loss by approximately $5.3 million. The decrease in property and other tax expense increased 2005 net income by approximately $1.0 million and was primarily the result of taxing jurisdictions in Michigan accepting the Company’s settlement offers related to outstanding property tax appeals.
The primary factors that negatively impacted earnings for 2005, when compared to 2004, were: (i) a premium associated with the repurchase of the CPS and Warrants; (ii) a non-cash debt extinguishment charge; (iii) increases in O&M expenses; (iv) increased depreciation expense; and (v) the absence from 2005 results of state income tax benefits recorded in 2004. The premium associated with the repurchase of the CPS and Warrants decreased net income by approximately $8.2 million. The non-cash debt extinguishment charge, which represents the write-off of unamortized debt issuance costs associated with long-term debt retired in 2005, decreased net income by approximately $0.9 million. The increase in O&M expenses, which decreased net income by approximately $2.9 million, was due primarily to increases in employee benefit and incentive costs, compensation, facilities costs, uncollectible customer accounts and various other operating expenses, due to the increasing cost of doing business. The increase in depreciation expense reduced net income by approximately $0.4 million. The state income tax benefits recorded in 2004 amounted to approximately $2.2 million and related to a change in estimate of the Company’s state income taxes for prior years. Combined financing costs for 2005, which include interest expense and dividends on both the CPS and Preferred Stock, were essentially unchanged from 2004.
The business segment analysis and other discussions on the next several pages provide additional information regarding the differences in operating results when comparing 2006, 2005 and 2004.
The Impact of Higher Natural Gas Prices
The market price of natural gas increased substantially during the second half of 2005. The Company believes this increase was caused, in large part, by the impact of Hurricanes Katrina and Rita on drilling, production, pipelines and processing facilities in and around the Gulf of Mexico, along with the supporting infrastructure and resources for those facilities. Since mid-December 2005, natural gas prices have receded from the higher levels established during the second half of 2005. This decline in prices may be attributable, among other factors, to reduced customer gas consumption in reaction to high prices, relatively warm weather during the first quarter of 2006 and December 2006 throughout the midwestern and eastern portions of the United States, the lack of any significant hurricanes in the Gulf of Mexico during 2006, and relatively high levels of working gas in storage during much of 2006 compared to average levels over the last five years. Despite the recent decrease in the market price of natural gas and lower-than-expected projected prices for the 2006-2007 winter heating season, as compared to the
prior year, future prices still remain relatively high beyond the winter heating season compared to average prices over the last five years. The Company believes that higher natural gas prices are likely in the future, and such higher prices will persist and that gas prices will remain volatile due to a variety of factors, including an apparent imbalance between natural gas supplies and demand resulting from, among other things, the use of substantial amounts of natural gas to generate electricity and environmental and other restrictions on natural gas exploration and production.
For customers in its Michigan service areas, the Company purchases natural gas supplies throughout the year, in order to (i) meet current customer needs, (ii) inject gas into storage for use by customers during the winter heating season, and (iii) have sufficient supplies under contract for the winter heating season. The decline in natural gas prices since mid-December 2005 has reduced the average price the Company has paid (though December 31, 2006) to purchase gas for the 2006-2007 winter heating season, when compared to the 2005-2006 winter heating season. Despite the decline, prices are still higher on average than they were a few years ago.
For customers in Alaska, the Company’s facilities are located near natural gas supplies, and the Company has RCA-approved gas purchase contracts with various Cook Inlet area producers. The price of gas purchased under these contracts is adjusted annually in January. A portion of the natural gas purchased by the Company for its Alaska customers is priced on a 36-month trailing average price for natural gas, so the price increases that occurred in the natural gas market during 2005 and early 2006 were not yet fully reflected in the price the Company paid for gas sold to customers in its Alaska service area through the end of 2006. However, the price the Company pays for gas under these contracts has increased over the past few years and, based on these trailing average prices and oil-based indexes in its other gas contracts, the Company expects to pay an average of $7.00 per Mcf for gas supplies under these contracts during 2007, compared to approximately $5.00 per Mcf during 2005. The price increase of approximately $2.00 per Mcf took effect on January 1, 2007.
In general, the cost of natural gas purchased for customers is recovered on a dollar-for-dollar basis (in the absence of disallowances), without a profit. The recovery of these gas costs is accomplished through the Company’s GCR pricing mechanisms, through which customer rates are periodically adjusted for increases and decreases in the cost of gas purchased by the Company for sale to customers. Refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the GCR pricing mechanisms.
When gas prices are volatile and increase substantially (such as occurred in the second half of 2005), the Company may require approval in certain of its regulatory jurisdictions to increase the commodity, or GCR, component of rates, to ensure the timely recovery of the cost of gas purchased for sale to customers. In addition, higher gas costs may decrease customer consumption, increase delinquent or uncollectible accounts, and increase the value of lost and unaccounted for (“LAUF”) natural gas volumes. These and other factors could result in an increase in working capital requirements and the need for the Company to borrow additional amounts under its Bank Credit Agreement or one or more Lines of Credit, if available.
The Company has been addressing, and continues to address, the impact of higher and more volatile natural gas prices by (i) seeking GCR rate increases in Michigan to recover the cost of gas on a timely basis, (ii) monitoring working capital requirements, (iii) evaluating customer consumption, (iv) monitoring customer payment patterns, and (vi) seeking changes in rate design (meaning the way in which the costs of providing service to customers are collected in rates) to help reduce the impact of higher and more volatile natural gas prices on the Company’s financial performance and align Company and customer interests with respect to conservation.
The MPSC-approved GCR rate affects approximately 250,000 customers in the Company’s service territory regulated by the MPSC. This GCR rate is set annually for the 12-month GCR period that runs from April 1 to March 31, but can be adjusted during the GCR period if actual gas costs incurred by the Company are significantly different than the prices initially used to determine this rate. Such a change in the GCR rate requires MPSC approval. The GCR rate for the approximately 37,000 customers in the service territory regulated by the CCBC is revised monthly, to track and recover changes in the cost of natural gas purchased by the Company for sale to Battle Creek area customers. The GCR rate for the approximately 126,000 customers in Alaska is established annually in January by the RCA, to reflect the pricing mechanisms in certain long-term gas supply contracts approved by the RCA, and recovers the cost of natural gas purchased by the Company under those contracts.
During the past 18 months, the Company has been successful in obtaining GCR rate increases on a timely basis to recover higher gas costs. Timely GCR rate changes have helped reduce the Company’s working capital requirements by eliminating the need to finance for an extended period any under-recovery of gas costs not recouped in current GCR rates. Higher gas costs have increased the Company’s need for additional working capital for other purposes, however, such as to finance gas purchases at higher market prices, finance storage inventory, and carry accounts receivable. The recent decline in natural gas prices has reduced the Company’s working capital requirements. However, working capital requirements would likely increase if natural gas prices increased again in the future. Refer to the section of Management’s Discussion and Analysis titled “Future Financing” for additional information regarding the utilization of the Company’s Bank Credit Agreement and Lines of Credit and the higher level of short-term borrowings being experienced by the Company.
The Company believes that higher gas costs, to the extent they are reflected in GCR rates, have affected, and will continue to affect, gas consumption by customers, who are induced by higher prices to conserve. Despite the recent decrease in the market price of natural gas in Michigan, from the highs established in the second half of 2005, prices for natural gas are still higher than they were a few years ago. In addition, customer rates in Alaska increased by approximately 30% on January 1, 2007, as a result of increases in prices under the Company’s RCA-approved long-term gas supply contracts, which are reflected in the GCR portion of customer rates. Based on these and other factors (including the possibility of future price increases), the Company is unable to estimate, with certainty, the amount of future conservation (if any) that is likely to occur. Based on normalized 2006 consumption, however, the Company estimates that every one percent decrease in customer consumption in Michigan may cause a decrease in 2007 gas sales margin of approximately $0.5 million to $0.6 million. Based on normalized 2006 consumption, the Company estimates that every one percent decrease in customer consumption in Alaska may cause a decrease in 2007 gas sales margin of approximately $0.3 million to $0.4 million. Refer to the section in Management’s Discussion and Analysis titled “The Impact of Weather and Energy Conservation” for customer consumption information for the years ended December 31, 2006, 2005 and 2004.
Higher gas costs, to the extent they are reflected in GCR rates, may also affect the ability of some customers to pay their bills for gas service on time or in full. The Company is, and has been, monitoring customer payment patterns and encouraging customers to elect budget-type levelized payment plans in order to spread winter heating season bills over a 12-month period. In addition to disconnecting service to delinquent customers, as necessary and permitted, the Company refers customers to sources of charitable and public assistance. The Company also participates in efforts to secure charitable donations that will provide such assistance.
The Company’s expense for uncollectible gas sales customer accounts as a percent of gas sales revenue was 0.56% for 2006, 0.42% for 2005 and 0.43% for 2004. Assuming that future expense for uncollectible accounts as a percent of annual gas sales revenue is similar to the experience in 2006, for each 10% increase in annual gas sales revenue (principally driven by the change in natural gas prices), there would be an expected increase in annual expense for uncollectible accounts of approximately $0.3 million. The Company’s expense for uncollectible gas sales customer accounts was $3.4 million, $2.4 million and $2.0 million for 2006, 2005 and 2004, respectively. The $1.0 million increase in expense for uncollectible gas sales customer accounts for 2006 when compared to 2005, was primarily attributable to higher gas prices (resulting in higher customer bills), reduced government funding of low income heating programs and rules limiting the ability of the Gas Distribution Business to terminate service to delinquent customers. The Company cannot provide any assurance that its future expense for uncollectible accounts will be consistent with its prior experience, in view of the various factors affecting customer payment patterns (including regulations governing service disconnections).
The Company also expects that higher gas costs will increase the expense associated with LAUF gas in its Michigan service areas, assuming that LAUF volumes are consistent with LAUF volumes in prior periods. Annual LAUF volumes in Michigan have ranged from 0.5% to 1.4% of volumes sold and transported in the Company’s Michigan service area over the last 10 years. The Company’s Michigan gas distribution operation typically accounts for 46% to 57% of total volumes sold and transported by the Company. LAUF gas volumes in Michigan for 2006 and 2005 were approximately 435 MMcf and 379 MMcf, respectively, or 0.82% and 0.65%, respectively, of volumes sold and transported in Michigan. The expense associated with LAUF gas in Michigan was $3.7 million and $2.9 million for 2006 and 2005.
The Company proposed to change various aspects of its rate design in the rate case it filed with the MPSC in 2006. A settlement of this rate case was approved in January 2007. The approved rate design changes are described in Note 2 of the Notes to the Consolidated Financial Statements in Item II, Part 8 of this 10-K. Except for a residential billing determinant change, the rate design changes proposed by the Company were not part of the settlement. The rate case order addressed the continuing decline in residential customer consumption by changing a key billing element included in residential base rates. In an MPSC order issued in the Company’s previous rate case proceeding in March 2005, residential base rates were set using annual customer usage of about 113 Mcf of natural gas. In the MPSC order issued on January 9, 2007, residential base rates were set using annual customer usage of 96 Mcf of natural gas. This significant reduction in the residential billing determinant recognizes that residential customer consumption has been steadily declining and sets base rates using an annual volume of gas consumption per customer that may be reasonably expected to be sold in a year with normal weather under current consumption patterns.
In future rate cases in Michigan and Alaska, the Company will continue to assess the need for rate design changes and propose changes that take into consideration the changing business environment in which the Company operates, including trends such as higher and more volatile natural gas prices and declining customer consumption.
The Impact of Weather and Energy Conservation
Temperature fluctuations and energy conservation have a significant impact on operating results of the Company. Accordingly, the Company believes that information about normal temperatures and consumption is useful for understanding its business and operating results. Consumption of natural gas for heating is largely determined by weather, and a portion of the Company’s revenues are collected through consumption-based charges. The Company’s budgets, forecasts and business plans are prepared using expected gas consumption under normal weather conditions and historical consumption patterns. The regulatory bodies that have jurisdiction over the rates charged by the Gas Distribution Business use weather-normalized consumption data to set customer rates and to establish authorized rates of return.
Many of the Company’s customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy saving devices and techniques. During the past several years, average annual per customer gas consumption has been decreasing. In addition, increases in natural gas prices appear to have increased conservation efforts by customers, prompting them, among other things, to “dial down” their thermostats. The Company expects this conservation trend to continue as an era of higher and more volatile natural gas prices influences customer consumption patterns.
The following table provides temperature and customer consumption data for the years 2004 through 2006:
(a)
Degree days are a measure of coldness determined daily as the number of degrees the average temperature during the day in question is below 65 degrees Fahrenheit. Degree days for a particular period are determined by adding the degree days incurred during each day of the period.
(b)
Normal degree days for a particular period is the average of degree days during the prior 15 years. Beginning in 2006, normal degree days for the Company’s Alaska operations is determined using a ten-year average of degree days rather than a 15-year average.
(c)
The percent by which actual degree days differ from normal degree days is often referred to as the percent by which temperatures were colder (warmer) than normal.
(d)
The percent by which actual degree days differ from prior period actual degree days is often referred to as the percent by which temperatures were colder (warmer) than the prior period.
(e)
Mcf is a quantity of natural gas equal to 1,000 standard cubic feet.
(f)
Normalized average annual gas consumption is determined by dividing the actual average gas consumption by actual degree days as a percent of normal degree days. The normalized average gas consumption represents an estimate of what average gas consumption would have been if during the period in question, actual degree days had equaled normal degree days.
(g)
The percent by which normalized average gas consumption differs from prior period normalized average gas consumption represents an estimate of the percentage change in gas consumption from one period to the next caused by factors other than temperature variations. This change can relate to various factors but is most likely due to changes in energy conservation by customers.
(h)
As a result of a gas supplier no longer supplying natural gas to certain transportation (large general service) customers in Alaska, these transportation customers have switched from gas (large general) transportation service to gas (large general) sales service. As large general service customers are much less weather sensitive, the Company has removed this category of customers from this calculation for all years presented.
The Company has estimated that in its Michigan service area, temperatures were approximately 11.8%, 0.1% and 0.3% warmer than normal during 2006, 2005 and 2004, respectively. In the Company’s Alaska service area, temperatures were estimated to be approximately 6.4% colder than normal during 2006 and 5.7% and 6.0% warmer than normal during 2005 and 2004, respectively.
Normalized average annual gas consumption for all gas sales customers in the Company’s Michigan and Alaska service areas decreased in 2006 and 2005 by a larger percentage than in previous years. The Company has estimated that in its Michigan service area, normalized average annual gas consumption during 2006 for all gas sales customers decreased by approximately 1.8%, when compared to 2005. In the Company’s Alaska service area, normalized average annual gas consumption during 2006 for all gas sales customers (excluding the large general service customers, some of which moved from transportation service) decreased by an estimated 2.3%, when compared to 2005.
The Company estimates that the combined variations from normal temperatures and normalized gas consumption decreased net income by approximately $3.5 million in 2006 and approximately $3.3 million during 2005. The Company estimates the impact on its operating results of combined variations from normal temperatures and normalized gas consumption by comparing average annual gas consumption per customer during a year to the normalized average annual gas consumption per customer for the prior year. The difference is multiplied by the average number of customers during the year to arrive at the total estimated increase or decrease in consumption associated with the combined variations from normal temperatures and normalized gas consumption. The total increase or decrease in consumption is multiplied by the actual gas sales margin per unit of gas consumption during the year to arrive at the estimated impact on operating results of combined variations from normal temperatures and normalized gas consumption.
Reportable Business Segments
The Company is required to disclose information regarding its reportable business segments. Business segments that do not exceed the quantitative thresholds required to be reportable business segments are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company has one reportable business segment: Gas Distribution. The operating results of this business segment are discussed on the following pages. There is also a discussion of the results for Corporate and Other. The Company evaluates the performance of its business segments based on operating income. Operating income does not include income taxes, interest expense, discontinued operations, or other non-operating income and expense items. A review of the non-operating items follows the Gas Distribution and Corporate and Other discussions. The business segment discussions should be read in conjunction with Item 1 of this Form 10-K. Refer to Note 11 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for further information regarding business segments and a summary of business segment financial information.
Gas Distribution Business Segment
Gas Sales Revenue. The Company’s gas sales revenue was $593.6 million, $569.1 million and $463.4 million for 2006, 2005 and 2004, respectively. The most significant factor causing the change in gas sales revenue from year-to-year is the change in the cost of gas sold. A significant portion of the Company’s cost of gas sold is accounted for by the Company’s GCR pricing mechanisms, which allow for the adjustment of rates charged to customers to reflect increases and decreases in the cost of gas purchased by the Company. Under these mechanisms, customers are charged rates that allow the Company to recoup its cost of gas purchased for sale to customers, subject, in the Company’s Michigan service territory regulated by the MPSC, to a review by the MPSC of the Company’s GCR gas purchase plan and the reasonableness of actual purchases and procurement practices. The CCBC periodically audits the Company’s gas supply procurement plans, which are substantially similar to the ones used to procure gas supplies for customers in the MPSC-regulated service area. In Alaska, gas supply contracts are reviewed by the RCA at the time the Company enters into those contracts. As a result of the use of these mechanisms, in the absence of disallowances, for any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in gas sales revenue. Refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for further information on cost of gas and the GCR mechanisms. Management generally evaluates changes in gas sales margin rather than gas sales revenue, due to the fluctuations caused by market-driven changes in cost of gas sold. Please refer to the gas sales margin section below for a detailed variance analysis:
The amounts in this table include intercompany transactions.
Gas Sales Margin. The Company’s gas sales margin is derived primarily from customer service charges and consumption-based distribution charges. The customer service charges are fixed amounts charged to customers each month. Distribution charges vary each month because they are based on the volume of gas consumed by customers. There are four primary factors that have historically impacted gas sales margin and, in the Company’s view, may impact future gas sales margin. These factors are changes in: (i) customer gas consumption; (ii) the number of gas sales customers; (iii) LAUF gas expense; and (iv) customer rates, including gas cost savings. In addition to these recurring items, two other factors have impacted results for 2005 and 2006. During 2005, the Company sold excess gas to a third-party gas supplier, which increased gas sales margin for 2005 by approximately $1.4 million. During late-2006, approximately 700 gas transportation customers in Alaska switched from gas transportation service to gas sales service, which increased gas sales margin by approximately $1.6 million. This service change-over occurred because a gas supplier stopped supplying natural gas to these transportation customers in late-2006. The gas for these new sales customers in Alaska is being supplied under the Company’s existing gas supply agreements. The Company’s margin from these customers after the date of the changeover to sales service is reported in gas sales margin rather than gas transportation revenue, resulting in the $1.6 million increase in gas sales margin. For all but one of these customers, however, the Company does not expect that this change from gas transportation service to gas sales service will affect the Company’s operating income significantly, because the margins under either service are the same. The Company has negotiated a special contract with one of the affected transportation customers, a public utility, which would result in future gas sales margins that would be higher than the margins the Company earned previously from this customer for providing transportation service. This special contract has been put into effect on an interim and refundable basis, pending final RCA approval.
Changes in customer gas consumption from one year to another have historically been attributable primarily to the impact of changes in temperatures between periods. More recently however, other factors (including conservation by customers, the increasing use of more energy efficient gas furnaces and appliances, the addition of new energy efficient homes to the Company’s gas distribution system and the price of natural gas) have contributed more significantly than in the past to changes in customer gas consumption. A decrease in customer gas consumption reduced gas sales margin for 2006 by approximately $4.6 million, when compared to 2005, and for 2005 by $3.6 million, when compared to 2004. During 2005, customer gas consumption was lower than expected, given that temperatures during 2005 were similar to temperatures during 2004. The Company believes the decrease in gas consumption for these years was due in large part to conservation prompted by the increased cost of natural gas. Refer to the discussion in Management’s Discussion and Analysis under the captions “The Impact of Higher Natural Gas Prices” and “The Impact of Weather and Energy Conservation” for further information on how changes in natural gas prices, temperature and energy conservation impact customer gas consumption.
The Company’s average number of gas distribution customers in Michigan (excluding customers acquired in the acquisition of Peninsular Gas in 2005) and Alaska has increased annually by an average of 1.1% and 3.3%, respectively, during the past three years. During 2006, the Company’s average number of gas distribution customers in Michigan (excluding customers acquired in the acquisition of Peninsular Gas in 2005) and Alaska increased by 0.6% and 3.2%, respectively, when compared to 2005. During 2005, the Company’s average number of gas distribution customers in Michigan (excluding customers acquired in the acquisition of Peninsular Gas in 2005) and Alaska increased by 1.3% and 3.4%, respectively, when compared to 2004. The additional customers increased gas sales margin for 2006 by approximately $2.4 million, when compared to 2005. Additional customers increased gas sales margin for 2005 by approximately $2.5 million, when compared to 2004. Customers added to the Company’s Michigan operation as a result of the acquisition of Peninsular Gas increased gas sales margin by approximately $0.5 million in 2006, when compared to 2005, and by approximately $0.5 million in 2005, when compared to 2004.
LAUF gas is a term used in the natural gas distribution industry to refer to the difference between the gas that is measured and injected into the Company’s gas distribution system and the amount of gas measured at customer meters. Typically, there is more gas measured as purchased and transported into a utility’s distribution pipeline system than is actually measured as sold and transported out of a utility’s distribution pipeline system. There are a number of reasons for LAUF gas, including measurement errors and leaks. The annual LAUF gas volumes in Michigan have ranged from 0.5% to 1.4% of total gas volumes sold and transported in Michigan over the last ten years. An increase in LAUF gas expense decreased gas sales margin for 2006 by approximately $0.8 million, when
compared to 2005. An increase in LAUF gas expense decreased gas sales margin for 2005 by approximately $0.1 million, when compared to 2004. The cost of LAUF gas is affected by the underlying commodity cost and rate mechanisms employed to price LAUF gas volumes and recover this cost from customers. Refer to the discussion in Management’s Discussion and Analysis under the caption “The Impact of Higher Natural Gas Prices,” for more information.
The remainder of the change in gas sales margin from 2005 to 2006, an increase of $2.6 million, was due primarily to changes in rates and gas cost savings as well as other miscellaneous factors. The remainder of the change in gas sales margin from 2004 to 2005, an increase of $7.5 million, was also due primarily to changes in rates and gas cost savings, as well as other miscellaneous factors. There was an increase in customer rates effective in March 2005 for MPSC-regulated customers. The rate increase for MPSC-regulated customers was the result of a settlement agreement approved by the MPSC. The CCBC approved new rates for CCBC-regulated customers, effective in April 2005, and the use of a GCR pricing mechanism, effective in April 2005. During 2004 and the first three months of 2005, the Company’s service area regulated by the CCBC was not operating under a GCR pricing mechanism and certain gas cost savings allowed under the terms of a gas supply and management agreement (which expired March 31, 2005) were retained by the Company. The gas cost savings realized under the agreement varied from year to year. For information on new rates and rate cases filed by the Company, refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. For further information regarding the Company’s natural gas supply and management agreements, GCR pricing mechanisms and gas cost savings, refer to the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Gas Transportation Revenue. The Company provides gas transportation services to customers who typically consume large volumes of natural gas. These customers purchase their natural gas directly from third-party suppliers. The natural gas purchased by customers from third-party suppliers is then transported on the Company’s gas distribution system to the customers. There was a $0.9 million decrease in gas transportation revenue in 2006, when compared to 2005. The decrease was primarily due to transportation customers in Alaska switching to gas sales service in the fourth quarter of 2006, as discussed under the caption “Gas Sales Margin,” and a decrease in transportation volumes for industrial and power plant customers, including the fertilizer manufacturer discussed below. These decreases were offset partially by an increase in transportation volumes to commercial customers as a result of colder weather in Alaska and an increase in commercial transportation customers during the first three quarters of 2006. There was a $0.1 million increase in gas transportation revenue in 2005, when compared to 2004. The increase was primarily due to higher rates and volumes to industrial customers and an increase in transportation volumes to commercial customers, partially offset by a decrease in transportation volumes to power plants.
One of the Company’s Alaska service area industrial transportation customers, a fertilizer manufacturer, has publicly announced that it has experienced difficulty in securing sufficient natural gas supplies at an appropriate price to continue operating in the future. The customer has indicated that it has secured sufficient natural gas supplies to operate at a reduced rate through October 2007, but currently does not have sufficient natural gas under contract at an appropriate price to operate after that date. Furthermore, during the winter period from October 2006 through March 2007, this facility has been shut down due to the lack of seasonal gas supply. Transportation revenues to this customer totaled $2.0 million in 2005 and $1.2 million in 2006. Based upon volumes transported during 2006 and estimates provided by the customer, transportation revenues to this facility are expected to total $0.8 million in 2007. The Company cannot predict the likely pattern of future operations at this plant, including whether the plant will ultimately close.
Other Operating Revenue. Increases in miscellaneous customer revenues and pipeline management revenues are the primary reasons for changes in other operating revenue during the past three years. In addition, a scheduled fee increase and a one-time settlement related to one of the Company’s large pipeline capacity contracts also contributed to the increase in other operating revenue in 2005. The miscellaneous customer revenues include various service fees and late payment fees charged to customers. An increase in these fees from 2005 to 2006 increased other operating revenue for 2006 by approximately $0.6 million. An increase in miscellaneous customer fees from 2004 to 2005 increased other operating revenue for 2005 by approximately $1.0 million.
Pipeline management revenue is earned by NORSTAR. These revenues were essentially unchanged in 2006, when compared to 2005. These revenues increased approximately $0.4 million in 2005, when compared to 2004, because of revenues earned from NORSTAR’s management of a pipeline construction project performed during 2005.
Operations and Maintenance Expenses. For the year 2006, O&M expenses increased by $5.8 million when compared to 2005. During 2005, O&M expenses increased by $5.8 million when compared to 2004. The most significant factors causing the changes in operating expenses during each of the past two years were increases in employee benefit costs and uncollectible customer accounts. These factors as well as other factors that impacted individual years are discussed below.
Employee benefit costs primarily include pension expense, medical coverage expense (including retiree medical coverage), and incentive compensation. For 2006, employee benefit costs increased by $3.1 million. Approximately 14% of the increase related to additional share-based compensation being expensed as a result of the adoption of Statement of Financial Accounting Standards (“SFAS”) 123-R, “Share-Based Payment,” while approximately 31% related to the granting of additional share-based compensation and other incentive compensation. The remainder (or approximately 55%) of the increase in employee benefit costs in 2006 was due primarily to increases in employee medical costs and pension costs. For 2005, employee benefit costs increased by approximately $2.6 million. Approximately 66% of this increase was due to increased pension expense while much of the remainder of the increase was due to an increase in incentive compensation.
Uncollectible customer accounts increased by approximately $1.0 million in 2006 when compared to 2005. By comparison, during 2005, uncollectible customer accounts increased by approximately $0.4 million, when compared to 2004. The increase in 2006 was primarily attributable to higher gas prices (resulting in higher customer bills), reduced government funding of low income heating programs and rules limiting the ability of the Gas Distribution Business to terminate service to delinquent customers. The increase in 2005 was due in large part to higher gas prices in 2005, offset partially by increased collection efforts and collection programs initiated by the Company.
The Company’s O&M expenses for 2006 included a charge of $1.2 million as a result of efforts to mitigate future costs associated with the lease for the Company’s former headquarters. During the first quarter of 2006, the Company was able to sublease this office space at less than the original lease rate, resulting in an improvement of future cash flow but a charge to earnings under the applicable accounting rules. For additional information, refer to Note 13 of the Notes to the Consolidated Financial Statements in Part II, Item 8, of this Form 10-K.
The remaining increases in O&M expenses from 2004 to 2005, and from 2005 to 2006, was caused by increases in compensation expense, facilities expense (including building and office lease expense), customer collection expense and various other expenses due primarily to inflationary pressures on expenses and the increased cost of doing business.
When expenses continue to increase as a result of inflation or other factors, the Company typically files base rate cases to recover the increased cost of doing business. Refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding recent rate case filings.
Depreciation and Amortization. The addition of new customers to the Company’s gas distribution system typically requires expansion of the system. In addition, the Company has a replacement program to ensure that older sections of its distribution system are upgraded and replaced, and the Company also typically upgrades and relocates parts of its system in connection with public works projects to improve roads and other public facilities. The increase in depreciation and amortization expense from year to year is due to depreciation on net additional property, plant and equipment placed in service as a result of expanding and upgrading the system.
Property and Other Taxes. The Company’s property and other taxes decreased for 2006 by approximately $0.8 million when compared to 2005. The Company’s property and other taxes decreased for 2005 by approximately $1.5 million when compared to 2004. These annual changes relate primarily to property taxes. During 2004, the Company recorded $1.4 million in additional property tax expense as a result of adjusting the amount it estimated it would recover from certain prior year property tax appeals. During 2005, the Company initiated settlement offers to all taxing jurisdictions involved with the prior year property tax appeals. Numerous taxing
jurisdictions have accepted the Company’s settlement offers and refunded property taxes to the Company. As a result, the Company reduced its 2006 and 2005 property tax expense by approximately $1.5 million and $0.5 million, respectively, to reflect these settlements. If the taxing jurisdictions that have not yet accepted the Company’s settlement offers were to accept the Company’s settlement offers, that would result in additional property tax refunds of approximately $0.4 million. The Company intends to pursue further refunds in 2007. Setting aside the impact of prior year property tax appeals and settlements, the Company’s property tax expense generally increases each year as a result of taxes on net additional property, plant and equipment placed in service as part of the expansion and upgrading of the Company’s gas distribution system. Refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information about the property tax appeals and the recovery of prior year excess property tax paid.
Regulatory, Environmental and Other Matters. In May 2006, the Company filed a request with the MPSC seeking authority to increase the base rates the Company charges to customers in its service areas regulated by the MPSC by $18.9 million. As part of this filing, the Company also proposed to change various aspects of the Company’s rate design (meaning the way in which the costs of providing service to customers is collected in base rates and other rates and charges). On December 29, 2006, the parties to the rate proceeding reached a settlement and filed the proposed settlement agreement with the MPSC. On January 9, 2007, the MPSC approved the settlement, as proposed, and issued an order for the implementation of the new rates for service rendered on and after January 10, 2007. Refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding the approved settlement and other regulatory matters.
In April 2006, the Company received a letter from Aurora Gas regarding the gas supply contract for natural gas deliveries to ENSTAR under the Moquawkie Contract. Aurora Gas asserted that production under the Moquawkie Contract was “Not Economic” as that term is defined in the Moquawkie Contract and said that it would suspend, and subsequently did suspend, deliveries effective October 1, 2006. Refer to Note 2 and Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding the lawsuit the Company has filed against Aurora Gas and steps the Company has taken to replace the suspended gas deliveries and recover the higher cost of the substitute gas.
In 2005, the Company entered into the 2005 Marathon Contract to supply a portion of the needs of the Company’s Alaska customers from 2009 through 2017. In November 2005, the Company submitted this gas supply contract to the RCA for its approval. In September 2006, the RCA rejected the contract and, in January 2007, Marathon exercised its right to terminate the contract. Refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding the RCA decision and the motions for reconsideration and/or clarification filed by the Company and other parties to the proceedings.
The Company has replaced the Customer Information System used for its Michigan operations. The Customer Information System is the primary computer program used to, among other things, bill customers for gas service. The Company put the system in service in October 2006 and is continuing to monitor its performance, which, to date, has been satisfactory.
For further information regarding regulatory matters and the application of the FASB’s Statement of Financial Accounting Standards (“SFAS”) 71, “Accounting for the Effects of Certain Types of Regulation,” refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K, the “Critical Accounting Policies” section of Management’s Discussion and Analysis and the “Rates and Regulation” section in Item 1 of this Form 10-K. For information regarding environmental matters and property tax litigation, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. Refer to the section titled “Gas Distribution Business Segment” in Item 1 of this Form 10-K for information on competition in this business segment.
Corporate and Other
The amounts in this table include intercompany transactions.
Operating Revenues. The Company’s businesses that are part of Corporate and Other, reported operating revenues of $18.2 million for 2006, $16.4 million for 2005 and $17.2 million for 2004. The $1.8 million increase for 2006, when compared to 2005, was due primarily to additional revenue from the sale of natural gas inventory. The $0.8 million decrease for 2005 when compared to 2004, was due primarily to a decrease in IT service revenues. IT revenues decreased because the Company generally has not been renewing contracts with non-affiliated customers, due to ongoing efforts to focus the IT operations primarily on the Company’s IT needs. This included work performed on a new Customer Information System and related system changes and upgrades, which were implemented in 2006.
Operating Income. Corporate and Other reported operating income of $2.7 million for 2006, compared to operating income of $1.5 million for 2005 and an operating loss of $7.3 million for 2004. The $1.2 million increase for 2006, when compared to 2005, was due primarily to additional margins from the sale of natural gas inventory and decreases in IT operating expenses and corporate professional fees. The 2005 results improved when compared to the 2004 results due in large part to $8.4 million in costs associated with the termination of the sale of the Company’s APC subsidiary included in the 2004 results. Also contributing to the improved results for 2005 were decreases in depreciation, IT and other miscellaneous expenses.
Other Income and Deductions
Interest Expense. Interest expense decreased by $1.6 million in 2006, when compared to 2005, and decreased by $1.2 million in 2005, when compared to 2004. The 2006 decrease was primarily due to lower levels of long-term debt as a result of the redemption of $10.3 million and $30.9 million of the Company’s 10.25% Series A Subordinated Debentures due 2040 (“10.25% Subordinated Notes”) in April 2005 and September 2005, respectively. The decrease in interest expense from lower levels of long-term debt was partially offset by higher average levels of short-term bank borrowings under the Company’s Bank Credit Agreement during the first half of 2006 and an increase in short-term interest rates related to the Company’s Bank Credit Agreement. The higher average level of short-term borrowings during the first half of 2006 was due primarily to the impact of warm weather during the first quarter of 2006, which resulted in a higher than normal amount of natural gas inventory on hand at the end of the 2005-2006 winter heating season. The Company utilizes short-term borrowings to finance the increased gas storage inventory levels. The 2005 decrease was also primarily due to lower levels of long-term debt as a result of the redemption of $10.3 million and $30.9 million of the Company’s 10.25% Subordinated Notes in April 2005 and September 2005, respectively, as discussed above.
Refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the retirement of the 10.25% Subordinated Notes in 2005.
Debt Exchange and Extinguishment Costs. During 2006 and 2005, in association with the Company redemption, at par, of certain of its long-term debt, the Company incurred $1.1 million and $1.5 million, respectively, of non-cash debt extinguishment charges in its Consolidated Statements of Operations. These charges represented write-offs of unamortized debt issuance costs related to debt redeemed in 2006 and 2005. For further information regarding the 2006 and 2005 debt redemptions, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Other Income. The $0.2 million increase in other income for 2006, when compared to 2005, was primarily due to an increase in equity earnings from the Company’s investment in ERGSS offset by lower interest income. The $0.3 million increase in other income for 2005, when compared to 2004, was primarily due to higher interest income (including allowance for funds used during construction (“AFUDC”)), partially offset by a decrease in equity earnings from the Company’s investment in ERGSS.
Income Taxes
The change in income taxes, when comparing one year to another, is due primarily to changes in income before income taxes and minority interest. However, in 2004, the Company made a change in the estimate of its state income taxes for prior years, which resulted in an additional income tax benefit of approximately $2.2 million. Refer to Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information on current and deferred income tax expense, deferred tax assets and liabilities, and recent net operating losses for tax purposes.
Discontinued Operations
Substantially all the operating assets of the Company’s construction services business were sold in September 2004. The Company has accounted for this business as a discontinued operation and, accordingly, the operating results and the loss on the disposal of this business are segregated and reported as discontinued operations in the Consolidated Statements of Operations. During 2005, the Company recorded additional income related to its discontinued construction services business as a result of a settlement of litigation. For additional information, including a component breakdown of operating results reflected in discontinued operations, refer to Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Dividends and Repurchase Premium on Convertible Preference Stock
The Company issued CPS in the first and second quarters of 2004. These securities and the paid-in-kind, non-cash dividends on them are described in Note 4 of the Notes to the Consolidated Financial Statements. These securities were redeemed in March 2005. Dividend expense for the CPS amounted to $0.9 million and $3.2 million for the years ended December 31, 2005, and 2004, respectively. The Company’s Consolidated Statements of Operations for 2005 also included an $8.2 million premium associated with the repurchase of the CPS in March 2005.
Dividends on Convertible Cumulative Preferred Stock
The Company issued 350,000 shares of Preferred Stock in March of 2005. The Preferred Stock and the cash dividends on the Preferred Stock are described in Note 4 of the Notes to the Consolidated Financial Statements. Dividend expense for the Preferred Stock amounted to $2.8 million and $3.0 million for the years ended December 31, 2006, and 2005, respectively. The decrease in dividends in 2006, when compared to 2005, was due to the retirement of 50,884 shares and 59,900 shares of Preferred Stock in April and May of 2006, respectively, partially offset by the fact that the Preferred Stock was not issued until March 2005. For additional information on the partial retirement of Preferred Stock, refer to Note 4 of the Notes to the Consolidated Financial Statements.
Liquidity and Capital Resources
Cash Flows Used For Investing. The Company’s Gas Distribution Business is capital intensive and a substantial amount of cash is spent annually on investments in property, plant and equipment. The following table identifies capital investments for the past three years:
Property additions for the Gas Distribution Business increased $1.5 million during 2006, when compared to 2005. Property additions for the Gas Distribution Business increased $0.8 million during 2005, when compared to 2004.
Property additions for Corporate and Other decreased $1.1 million during 2006, when compared to 2005. The decrease was primarily due to costs incurred in 2005 related to the acquisition of office furniture and equipment and leasehold improvements for the Company’s new leased office facilities. Property additions for Corporate and Other increased $0.4 million during 2005, when compared to 2004. The increase was primarily due to leasehold improvement costs incurred for the Company’s leased office facilities.
In addition, the Company acquired substantially all of the assets and certain liabilities of Peninsular Gas on June 1, 2005. The Company paid approximately $2.8 million, net of cash acquired, for this acquisition in the second quarter of 2005 and an additional $0.3 million in the third quarter of 2005. For further information, refer to Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
In 2007, the Company plans to spend approximately $39.7 million on property additions.
Cash Flows Provided by Operations. The Company’s net cash provided by operating activities totaled $76.7 million in 2006, $28.8 million in 2005 and $40.2 million in 2004. The change in operating cash flows is influenced by changes in the level and cost of gas in underground storage, changes in accounts receivable and accounts payable and other working capital changes. The changes in these accounts are largely the result of the timing of cash receipts and payments. The Company’s largest use of cash is for the purchase of natural gas for sale to its customers. Generally, gas is injected into storage during the months of April through October and withdrawn for sale from November through March. The Company may also use significant amounts of short-term borrowings to finance natural gas purchases for storage during the non-heating season. The change in cash provided by operating activities is also impacted by changes in the operating results of the Company’s businesses.
The increase in cash flows from operating activities during 2006 was due primarily to lower average gas prices in 2006, when compared to 2005, and warmer temperatures in the fourth quarter of 2006, compared to 2005. The combination of lower gas prices and warmer temperatures at the end of 2006 resulted in a significant decrease in accounts receivable and accrued revenue from December 31, 2005, to December 31, 2006. Lower gas prices also reduced the average cost of gas in storage at December 31, 2006, compared to December 31, 2005. However, this decrease was offset by an increase in the volume of gas in storage at December 31, 2006, due to lower gas sales as a result of warmer temperatures.
The decrease in cash flows from operating activities during 2005 was due primarily to a substantial increase in the market price of natural gas purchased in the last half of 2005. As a result, the cost of the Company’s gas in underground storage at December 31, 2005, was approximately $29 million higher than it was at December 31, 2004. The higher cost of gas was also reflected in customer rates, which caused a significant increase in accounts receivable from December 31, 2004, to December 31, 2005. The impact of higher gas prices on operating cash flow was partially offset by more favorable credit terms the Company obtained from various gas suppliers during 2005.
For additional information concerning the recent increases in natural gas prices, refer to the discussion in Management’s Discussion and Analysis, under the caption “The Impact of Higher Natural Gas Prices”.
Cash Flows Provided by Financing. The Company’s net cash provided by (used for) financing activities totaled $(33.2) million, $15.8 million and $(28.5) million in 2006, 2005 and 2004, respectively.
On October 31, 2006, the Company entered into a bank term loan agreement in the amount of $55 million (the “Bank Term Loan”). The Bank Term Loan matures on June 30, 2016, and is callable at any time at the option of the Company. Interest on the Bank Term Loan is payable at variable rates based on LIBOR plus an applicable margin. The Company received the proceeds of the Bank Term Loan on November 29, 2006. The proceeds were used to retire a portion of the $59.5 million principal amount outstanding of the Company’s 8% Series Notes due 2016. On November 1, 2006, the Company called for redemption of $59.5 million of its 8% Senior Notes due 2016, at a redemption price equal to 100% of the principal amount plus accrued interest. These notes were redeemed on November 30, 2006.
On April 24, 2006, the Company issued 865,028 shares of the Company’s Common Stock and paid $5.0 million in cash to a holder of the Company’s Preferred Stock, in exchange for 50,884 shares of Preferred Stock, which were retired. On May 26, 2006, the Company issued 689,996 shares of the Company’s Common Stock and paid $7.6 million in cash to another holder of the Company’s Preferred Stock, in exchange for 59,900 shares of Preferred Stock, which were retired. The components of these transactions that do not involve the exchange of cash are not reflected in the Company’s Consolidated Statements of Cash Flows.
During 2004, the Company issued, through a private placement to K-1 GHM, LLP, an affiliate of a private equity firm, K1 Ventures Limited (“K-1”), $50 million of CPS and Warrants to purchase 905,565 shares of the Company’s Common Stock. The net proceeds (proceeds less issuance costs) from the issuance amounted to approximately $46.3 million and were used to pay down short-term debt and invest temporarily in cash equivalents. In June 2004, a portion of the proceeds invested temporarily in cash equivalents was used to redeem all $29.9 million of its outstanding 8% Senior Notes due 2010 at par. The Company paid stock dividends on the CPS of 1,766 additional shares of CPS during 2004.
During the first quarter of 2005, the Company repurchased all of the CPS (52,543 shares) and Warrants (905,565 Warrants) held by K-1. The aggregate purchase price for the CPS and Warrants was $60 million. During
the first quarter of 2005, the Company also completed the sale of 350,000 shares of Preferred Stock. The gross proceeds from this offering were approximately $70 million, of which $60 million was used to fund the repurchase of CPS and Warrants from K-1. The remaining proceeds were used to redeem $10.3 million principal amount of the Company’s 10.25% Subordinated Notes held by SEMCO Capital Trust I. The Trust, in turn, used the proceeds to redeem 400,000 Trust Preferred Securities and 12,371 common securities on April 29, 2005.
During the third quarter of 2005, the Company completed an offering of 4,945,000 shares of Common Stock. The proceeds from this offering were used to redeem the remaining $30.9 million of the 10.25% Subordinated Notes held by the Trust. The Trust, in turn, used the proceeds from the redemption of the 10.25% Subordinated Notes to redeem the remaining 1.2 million Trust Preferred Securities and 37,114 common securities on September 14, 2005.
For further information regarding these transactions, refer to Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
In June 2004, the Company suspended the quarterly cash dividend on the Company’s Common Stock, with the objective of supplementing free cash flow. In addition, the decision reflected the Company’s desire to retain cash in order to strengthen its balance sheet, enhance financial flexibility and to be better positioned to grow the Company’s Gas Distribution Business in the future. Cash dividends paid per share for common shareholders were $0.15 in 2004.
Non-Cash Financing Activities. For information regarding non-cash financing activities, refer to the caption “Statements of Cash Flows” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Pension Plans and Other Post Retirement Benefits. The Company has defined-benefit pension plans (“Pension Plans”) that cover approximately 99% of the Company’s employees. During 2006, the Company contributed $6.7 million to fund benefits payable under the Pension Plans. The Company anticipates that the annual contribution to fund the Pension Plans in 2007 will be approximately $4.7 million. Such contributions will come from amounts collected in Gas Distribution Business rates or through short-term borrowings.
The Company provides certain medical and prescription drug benefits to approximately 293 eligible retired employees and their surviving spouses under postretirement benefit plans (“Postretirement Plans”). During 2006, the Company paid approximately $1.3 million to cover the costs of the Postretirement Plans out of its corporate assets. The Company anticipates that the annual payments to cover the costs of the Postretirement Plans in 2007 will be approximately $1.6 million and will be paid out of corporate assets or its funded postretirement benefit plans. For additional information, refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Future Financing. In general, the Company funds its capital expenditures with operating cash flows and borrowings under its Bank Credit Agreement and Lines of Credit. When appropriate, the Company will refinance its short-term debt with long-term debt, Common Stock issuances or other long-term financing instruments.
The Company’s capital structure at December 31, 2006, consisted of approximately 65.4% total debt (including current maturities and notes payable), 5.9% preferred stock and 28.7% common equity. The Company continues to assess its overall liquidity and capital structure, with a view to migrating over time to a capital structure that is consistent with that of an investment grade company. One of the Company’s primary goals is to increase equity as a percentage of total capital while reducing the Company’s overall debt to total capital ratio. Although there are no current specific plans to reduce long-term debt in 2007, the Company will continue to identify and, as appropriate, take advantage of market opportunities to do so as they arise. For example, the Company may, if the opportunity arises, prepay portions of the Bank Term Loan during the 2007 through 2010 period.
On June 14, 2005, a universal shelf registration statement on Form S-3 (“June 2005 Registration Statement”) filed by the Company with the SEC became effective. The Company registered an aggregate of $150 million of various securities under the June 2005 Registration Statement. Subsequent to the effectiveness of the June 2005 Registration Statement, the Company completed a Common Stock offering of $31.3 million, leaving $118.7 million of securities available for possible future issuances of Common Stock, preferred stock, trust preferred securities and long-term debt. At the present time, the Company does not meet the requirements under its indentures to issue
additional senior notes but the Company is permitted to refinance maturing debt. Long-term debt of the Company scheduled to mature during the next five years includes $150 million of 7.125% notes due in 2008, $5 million of 6.40% notes due in 2008 and $30 million of 6.49% notes due in 2009.
The Company has an unsecured $120 million revolving Bank Credit Agreement, which expires on September 15, 2008. Interest paid under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. LIBOR-based borrowings are permitted for periods ranging from two weeks to one, two, three or six months. At December 31, 2006, the Company was utilizing $58.5 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $61.5 million of the borrowing capacity unused. The $58.5 million of capacity being used consisted of $7.8 million of letters of credit and $50.7 million of borrowings. These amounts will change from time to time reflecting the Company’s then current working capacity needs. Refer to Note 5 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding the Bank Credit Agreement, including a description of the covenants contained therein. As of December 31, 2006, the Company was in compliance with the Bank Credit Agreement covenants.
In the fourth quarter of 2006, the Company established three unsecured discretionary bank lines of credit totaling $37.5 million, which expire at various dates in 2007 (collectively with the additional line of credit described in the next paragraph, the “Lines of Credit”). The banks are not obligated to make any advances under the Lines of Credit and may at any time, without notice, in their sole and absolute discretion, refuse to make advances to the Company. Interest paid under the Lines of Credit is at variable rates, which are based upon prime lending rates or rates quoted by the bank. At December 31, 2006, the Company was utilizing $15 million of the borrowing capacity available under these Lines of Credit. Refer to Note 5 of the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information regarding these Lines of Credit.
On January 5, 2007, the Company entered into an additional Line of Credit with a borrowing capacity of $15 million. This Line of Credit will expire on October 31, 2007, and together with the Company’s other Lines of Credit, gives the Company access to $52.5 million of additional borrowing capacity. However, the Company anticipates that, under these arrangements with various lenders, at any given time, its total outstanding advances under the four current Lines of Credit, collectively, will not exceed $15 million at the end of each quarter. The Company currently intends to use amounts advanced under such arrangements primarily to finance the Company’s working capital needs. The advances under these arrangements may fluctuate materially, given the seasonality of the Company’s business.
The Company’s Gas Distribution Business is seasonal in nature. During the winter heating season, higher volumes of gas are sold, resulting in peak profitability during the fourth and first quarters of the year. The Company’s cash flow and its corresponding use of its Bank Credit Agreement and Lines of Credit typically also will follow a seasonal pattern. The Company expects to use funds available under the Bank Credit Agreement and Lines of Credit to finance, on a short-term basis, the variability and seasonality of its operating cash flow and working capital requirements. Typically, as the Company collects cash from winter heating sales in the latter part of the first quarter and the second quarter, it will pay down the borrowings under the Bank Credit Agreement and Lines of Credit. During the summer months, it will reduce its short-term borrowings under the Bank Credit Agreement and Lines of Credit, and may build up sufficient cash to enable it to enter into short-term investments. As gas is purchased throughout the summer and injected into storage in preparation for the winter heating season and the Company completes its annual construction program, the Company expects to incur borrowings under the Bank Credit Agreement and Lines of Credit. Such borrowings typically begin during the third quarter and intensify, such that the maximum short-term borrowings occur around the end of the year. As winter sales occur and gas sales revenues are billed and collected, the Company again begins to reduce its short-term borrowings in the first quarter. This borrowing pattern can also be affected by numerous factors, including the credit terms under which the Company purchases natural gas for sale to customers, its GCR factors in various jurisdictions and its relative levels of gas storage inventory.
Business Development Initiatives. In the event that the Share Exchange or a similar transaction is not consummated, the Company would likely consider, among other things, acquisitions of, or investments in, local distribution, pipeline, and gas storage businesses and assets. These acquisitions and investments are typically
considered pursuant to confidentiality agreements, which, among other things, allow the exchange of data subject to non-disclosure requirements (usually barring the disclosure or misuse of such data and requiring that the fact of discussions of a possible acquisition or investment be kept secret). The Company generally will not make any public announcement of such activities until definitive agreements with respect thereto have been signed.
Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. The Company’s ratio of earnings to fixed charges, as defined under Item 503 of SEC regulation S-K, was 1.37 for 2006, 1.40 for 2005 and 1.06 for 2004. The Company’s ratio of earnings to combined fixed charges and preferred stock dividends, as defined under Item 503 of SEC regulation S-K, was 1.25 for 2006 and less than a one-to-one coverage for 2005 and 2004. The amount of earnings that would be required to attain a ratio of one-to-one for 2005 and 2004 are approximately $0.9 million and $3.4 million, respectively.
Off-Balance Sheet Arrangements. The Company does not have any off-balance sheet financing arrangements as defined in Item 303(a)(4) of Regulation S-K.
Guarantees. The Company has letters of credit that are required to be disclosed under the provisions of Financial Accounting Standards Board Interpretation No. 45, “Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” For information on these letters of credit, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Contractual Obligations and Commercial Commitments. Summarized below are the contractual obligations and commercial commitments of the Company as of December 31, 2006:
(a)
The indentures, under which long-term debt of $150 million due 2008 and $200 million due 2013 was issued, contain provisions that upon the occurrence of a change of control of the Company, the Company shall make an offer to repurchase all or any part of the notes at a purchase price equal to 101% of the aggregate principal amount of the notes. Such a change of control would occur upon the closing of the transaction described under the caption “Pending Sale of the Company” in Part I, Item 1 of this Form 10-K. Cap Rock has obtained financing commitments sufficient to fund any such repurchase.
(b)
Under the terms of the agreements which govern the Bank Term Loan and Bank Credit Agreement, an event of default would occur upon a change of control of the Company. In such an event, the lenders may declare any outstanding amounts immediately due and payable. Such a change of control would occur upon the closing of the transaction described under the caption “Pending Sale of the Company” in Part I, Item 1 of this Form 10-K. Cap Rock has obtained financing commitments sufficient to fund any such amounts that may become due.
Other Commitments and Contingencies. For information about other commitments and contingencies, refer to Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Market Risk Information
The Company’s primary market risk arises from fluctuations in natural gas and propane prices and interest rates. The Company’s exposure to commodity price risk arises from changes in natural gas and propane prices throughout the United States and in eastern Canada, where the Company conducts sales and purchase transactions. The Company does not currently use financial derivative instruments (such as swaps, collars or futures) to manage its exposure to commodity price risk. A significant portion of the natural gas requirements of the Company’s Michigan gas distribution operations are covered under third-party supply arrangements and the GCR mechanism through which commodity costs are paid by customers. ENSTAR’s natural gas requirements are primarily covered by a number of RCA-approved long-term supply arrangements and the GCR mechanism through which related commodity costs are paid by customers. For further information on how these agreements and mechanisms reduce the Company’s exposure to commodity price risk, see the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
The Company is also subject to interest rate risk in connection with the issuance of variable and fixed-rate debt. In order to maintain its desired mix of fixed-rate and variable-rate debt, the Company may use interest rate swap agreements and exchange fixed and variable-rate interest payment obligations over the life of the agreements, without exchange of the underlying principal amounts. See Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on interest rate swap agreements and how the Company accounts for its risk management activities.
For information regarding the fair value of the Company’s financial instruments, refer to Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. The following table provides information about the Company’s financial instruments that are sensitive to interest rate changes as of December 31, 2006:
(a)
The average interest rate reported for the variable rate long-term debt is the average rate during the year ended December 31, 2006.
(b)
Amount represents the total that would be permitted to be outstanding through a combination of utilizing the $120 million available to the Company from its Bank Credit Agreement and the $37.5 million of total credit potentially available to the Company from its Lines of Credit at December 31, 2006, rather than the actual amount outstanding at December 31, 2006. For further information on the Company’s Bank Credit Agreement and its Lines of Credit, refer to Note 5 of the Consolidated Notes to the Financial Statements in Item 8 of this Form 10-K.
(c)
The average interest rate reported for the variable rate bank credit facilities is the average rate during the year ended December 31, 2006.
(d)
The indentures, under which long-term debt of $150 million due 2008 and $200 million due 2013 was issued, contain provisions that upon the occurrence of a change of control of the Company, the Company shall make an offer to repurchase all or any part of the notes at a purchase price equal to 101% of the aggregate principal amount of the notes. Such a change of control would occur upon the closing of the transaction described under
the caption “Pending Sale of the Company” in Part I, Item 1 of this Form 10-K. Cap Rock has obtained financing commitments sufficient to fund any such repurchase.
(e)
Under the terms of the agreements which govern the Bank Term Loan and Bank Credit Agreement, an event of default would occur upon a change of control of the Company. In such an event, the lenders may declare any outstanding amounts immediately due and payable. Such a change of control would occur upon the closing of the transaction described under the caption “Pending Sale of the Company” in Part I, Item 1 of this Form 10-K. Cap Rock has obtained financing commitments sufficient to fund any such amounts that may become due.
Impact of Inflation
The cost of gas purchased by the Gas Distribution Business for sale to customers is recovered from customers through GCR pricing mechanisms. The GCR pricing mechanisms allow for the adjustment of rates charged to customers to reflect, in the absence of cost disallowances, increases and decreases in the cost of gas purchased by the Company. See the caption “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers” in Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for more information on these mechanisms. Increases and decreases in customer rates under the GCR pricing mechanisms generally occur annually but can occur more frequently in certain circumstances and occur monthly in the service area regulated by the CCBC. The price of natural gas increased substantially during the last half of 2005, but while still historically high, has receded from those levels during 2006. For information regarding the impact of higher natural gas prices on the Company, refer to the risk factors in Item 1A and the caption “The Impact of Higher Natural Gas Prices” in Item 7 of this Form 10-K.
Increases in other operating costs are recovered in MPSC-, CCBC- and RCA-approved rates, typically as a result of base rate filings made by the Company. Recovering cost increases through this process may adversely affect the results of operations due to the time lag involved securing necessary rate approvals and the decisions made on the merits of the Company’s requests. The Company attempts to minimize the impact of inflation by controlling costs, increasing productivity and filing base rate cases on a timely basis. For information on the Company’s latest rate cases, refer to Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Policies
The Company has prepared its Consolidated Financial Statements in conformity with accounting principles generally accepted in the U.S. The preparation of these financial statements 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 and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies under which judgments or uncertainties could affect the application of those policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Rate Regulation. The Gas Distribution Business is subject to regulation. The regulatory matters associated with gas distribution customers located in the City of Battle Creek, Michigan, and surrounding communities are subject to the jurisdiction of the CCBC. The MPSC has jurisdiction over the regulatory matters related to the Company’s remaining Michigan customers. Regulatory matters for gas distribution customers in Alaska and APC are subject to the jurisdiction of the RCA. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures, and standards of service.
The Gas Distribution Business has accounting policies, which conform to SFAS 71, “Accounting for the Effect of Certain Types of Regulation,” and which are in accordance with the accounting requirements and ratemaking practices of the MPSC, CCBC and RCA. The application of these accounting policies allows the Company to defer expenses and income as regulatory assets and liabilities in the Consolidated Statements of Financial Position when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the
period in which they would have been reflected in the Consolidated Statements of Operations by an unregulated business. These deferred regulatory assets and liabilities are then included in the Consolidated Statements of Operations in the periods in which the same amounts are reflected in rates. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Statements of Financial Position and included in the Consolidated Statements of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as extraordinary items.
Goodwill. The Company evaluates its goodwill for impairment in accordance with SFAS 142, “Goodwill and Other Intangible Assets.” SFAS 142 requires that the Company perform impairment tests on its goodwill balance annually or at any time when events occur that could impact the value of the Company’s business segments. The Company’s determination of whether an impairment has occurred is based on an estimate of discounted cash flows attributable to the Company’s reporting units that have goodwill, as compared to the carrying value of those reporting units’ net assets. The Company must make long-term forecasts of future revenues, expenses and capital expenditures related to the reporting unit in order to make the estimate of discounted cash flows. These forecasts require assumptions about future demand, future market conditions, regulatory developments and other factors. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. If an impairment test of goodwill shows that the carrying amount of the goodwill is in excess of the fair value, a corresponding impairment loss would be recorded in the Consolidated Statements of Operations.
The 2005 and 2006 annual impairment tests were performed for the Company’s business segments and indicated that there was no impairment of goodwill for any of its business segments. The 2004 annual impairment tests were performed for the Company’s business segments and indicated that there was an impairment of goodwill at the Company’s IT services business. For further information on these impairments, see Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Pensions and Other Postretirement Benefits. The Company accounts for pension costs and other postretirement benefit costs in accordance with the SFAS 87, “Employers’ Accounting for Pensions” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively. These statements require liabilities to be recorded in the Consolidated Statements of Financial Position at the present value of these future obligations to employees net of any plan assets. The calculation of these liabilities and associated expenses require the expertise of actuaries and are subject to many assumptions, including life expectancies, present value discount rates, expected long-term rate of return on plan assets, rate of compensation increase and anticipated health care costs. The discount rate used by the Company is determined by reference to the CitiGroup pension discount curve, other long-term corporate bond measures and the expected cash flows of the plans. The duration of the securities underlying those indexes reasonably matches the expected timing of anticipated future benefit payments. The expected long-term rate of return on plan assets is established based on the Company’s expectations of asset returns for the investment mix in its plans (with some reliance on historical asset returns for the plans). The expected returns of various asset categories are blended to derive an appropriate long-term assumption.
Any change in these assumptions can significantly change the liability and associated expenses recognized in any given year. For example, a one percentage point increase in anticipated health care costs each year would increase the accumulated retiree medical obligation as of December 31, 2006, by $6.6 million and the aggregate of the service and interest cost components of net periodic retiree medical costs for 2006, by $0.5 million. For further sensitivity analyses, refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
New Accounting Standards
In June 2006, the FASB issued Financial Interpretation Number (“FIN”) 48, “Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109.” In September 2006, the FASB issued SFAS 157, “Fair Value measurements” and SFAS 158, “Employers’ Accounting Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB
Statement No. 115.” Refer to the “New Accounting Standards” section of Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K for information on these new accounting standards.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
For the information required pursuant to this item, refer to the section titled “Market Risk Information” in Item 7 of this Form 10-K.
Item 8.
Item 8.
Financial Statements and Supplementary Data
This item includes the following information in the order shown:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Financial Position
Consolidated Statements of Cash Flows
Consolidated Statements of Capitalization
Consolidated Statements of Changes in Common Shareholders’ Equity
Consolidated Statements of Comprehensive Income
Notes to the Consolidated Financial Statements
Financial Statement Schedule II - Consolidated Valuation and Qualifying Accounts
All other financial statement schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
SEMCO Energy, Inc.:
We have completed integrated audits of SEMCO Energy, Inc.’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 SEMCO Energy, Inc. and its subsidiaries 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 8 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement benefit plans as of 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Detroit, Michigan
March 12, 2007
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes to the consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
The accompanying notes to the consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
The accompanying notes to the consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes to the consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS EQUITY
The accompanying notes to the consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes to the consolidated financial statements are an integral part of these statements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1.
Company Description and Significant Accounting Policies
Company Description. SEMCO Energy, Inc., is a New York Stock Exchange-listed regulated public utility headquartered in Port Huron, Michigan. References to the “Company” mean SEMCO Energy, Inc., SEMCO Energy, Inc. and its subsidiaries, individual subsidiaries or divisions of SEMCO Energy, Inc. or the segments discussed below, as appropriate in the context of the disclosure.
The Company reports one reportable business segment: Gas Distribution. The Company’s Gas Distribution business segment distributes and transports natural gas to approximately 287,000 customers in Michigan and approximately 126,000 customers in Alaska. These operations are known together as the “Gas Distribution Business.” The Gas Distribution Business is subject to regulation, which is discussed in the “Rate Regulation” section below. This business segment accounted for approximately 98% of the Company’s 2006 consolidated operating revenues.
The Company’s other business segments do not meet the quantitative thresholds required to be reportable business segments (“non-separately reportable business segments”) and are combined and included with the Company’s corporate division in a category the Company refers to as “Corporate and Other.” The Company’s non-separately reportable business segments primarily include operations and investments in information technology (“IT”) services, propane distribution, intrastate natural gas pipelines, and a natural gas storage facility. The IT services operation is located in Michigan and provides IT services with a primary focus on the Company’s IT needs. For 2006, this focus included the implementation of a new Customer Information System and related system changes and upgrades. The Company does not currently provide IT services to non-affiliated customers but may do so in the future where it believes it can do so profitably. The Company’s propane distribution operation typically sells approximately 4 million gallons of propane annually to retail customers in Michigan’s Upper Peninsula and northeast Wisconsin. The Company’s pipeline and storage operations own and operate natural gas transmission and storage facilities in Michigan.
Discontinued Operations. During the first quarter of 2004, the Company began accounting for its construction services business as a discontinued operation. In September 2004, the Company sold the assets of its construction services business to InfraSource Services, Inc. for approximately $21.3 million. For additional information refer to Note 14.
Basis of Presentation. The financial statements of the Company were prepared in conformity with accounting principles generally accepted in the United States. In connection with the preparation of the financial statements, management was required 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 and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.
Principles of Consolidation. The consolidated financial statements include the accounts of SEMCO Energy, Inc. and its wholly-owned subsidiaries. Investments in unconsolidated companies where the Company has significant influence, but does not control the entity, are reported using the equity method of accounting.
Rate Regulation. The Gas Distribution Business is subject to regulation. The Michigan Public Service Commission (“MPSC”) has jurisdiction over the regulatory matters related to the Company’s Michigan customers, except for customers in the City of Battle Creek, Michigan, and nearby communities. The City Commission of Battle Creek (“CCBC”) has jurisdiction over the regulatory matters related to the Company’s customers in the City of Battle Creek, Michigan and nearby communities. The Regulatory Commission of Alaska (“RCA”) has jurisdiction over the regulatory matters related to the Company’s Alaska customers. These regulatory bodies have jurisdiction over, among other things, rates, accounting procedures, and standards of service. The approximate number of the Company’s customers located in service areas regulated by each of the three regulatory bodies is as follows: MPSC - 250,000; CCBC - 37,000; and RCA - 126,000.
The Gas Distribution Business is subject to Statement of Financial Accounting Standards (“SFAS”) 71. Refer to Note 2 for additional information regarding SFAS 71.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
Cash and Cash Equivalents. Cash and cash equivalents include cash on hand, money market funds, and commercial paper with original maturities of three months or less.
Restricted Cash. At December 31, 2006, and 2005, the Company had $3.6 million and $1.6 million, respectively, of restricted cash. Restricted cash includes the portion of a supplemental retirement trust account expected to be distributed within one year, and deposits to an escrow account to comply with credit requirements of two of the Company’s gas suppliers.
Accounts Receivable. Trade accounts receivable are recorded at the billed amount and do not bear interest. The allowance for doubtful accounts is the Company’s estimate of the amount of probable credit losses in existing accounts receivable. Allowance for doubtful accounts is based primarily on the aging of receivables, while also taking into consideration historical write-off experience and regional economic data. The Company reviews allowance for doubtful accounts monthly. Account balances are charged off against the allowance when the Company determines it is probable that certain individual receivables will not be recovered. Uncollectible accounts, or bad debt expense, was $3.4 million, $2.4 million and $3.1 million for 2006, 2005 and 2004, respectively.
Accrued Revenue. Accrued revenue represents revenue earned in the current period but not billed to the customer until a future date, usually within one month.
Gas in Underground Storage. The gas inventory of the Gas Distribution Business at December 31, 2006, and 2005, was reported at average cost. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas.
Property, Plant, Equipment and Depreciation. The Company’s property, plant and equipment are recorded at cost. The Company provides for depreciation on a straight-line basis over the estimated useful lives of the related property. The lives over which the Company’s significant classes of regulated and non-regulated depreciable property are depreciated are as follows (in years):
The ratio of depreciation to the average balance of regulated property was approximately 3.7%, 3.8% and 3.8% for the years 2006, 2005 and 2004, respectively. The ratio of depreciation to the average balance of non-regulated property approximated 3.3%, 3.5% and 4.2% for the years 2006, 2005 and 2004, respectively.
Depreciation rates on the Company’s regulated property are set by the regulatory commissions that have jurisdiction over the property. The depreciation rates are intended to expense, over the expected life of the property, both the original cost of the property and the expected costs to remove or retire the property at the end of its useful life. The portion of depreciation expense related to expensing the original cost of the property is charged to accumulated depreciation, while the portion related to expensing the expected costs to remove or retire the regulated property, less expected salvage proceeds, is charged to a regulatory liability. This regulatory liability is known in the utility industry as negative salvage value. When the regulated property is ultimately retired, or otherwise disposed of in the ordinary course of business, the original cost of the property is charged to accumulated depreciation, and the actual removal costs, less salvage proceeds, are charged to the regulatory liability. With respect to the retirement or disposal of non-regulated assets, the resulting gains or losses are recognized in income.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
During 2004, under the provisions of SFAS 144, “Accounting for Impairment or Disposal of Long-Lived Assets,” the Company recorded a $0.2 million charge in the fourth quarter of 2004 for the impairment of long-lived assets. The impairment charge was a result of the Company’s decision to exit the residential portion of its Internet Service Provider (“ISP”) operation that was part of its IT business. The $0.2 million before-tax charge for impairment of long-lived assets is reflected in the Company’s Consolidated Statements of Operations in operations and maintenance expenses.
Asset Retirement Obligations. The Company accounts for asset retirement obligations under the provisions of SFAS 143, “Accounting for Asset Retirement Obligations” and Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations (“FIN 47”).” SFAS 143 requires companies to record the fair value of the cost to remove assets at the end of their useful life, if there is a legal obligation to remove them. FIN 47 clarifies the term “conditional asset retirement obligation” as used in SFAS 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
The Company has identified certain assets for which asset retirement obligations must be recognized. At December 31, 2006, and December 31, 2005, the Company estimated that the cost of retiring these assets at the date of removal would be $28.2 million and $24.1 million, respectively. The present value of these obligations at December 31, 2006, and December 31, 2005, was $2.9 million and $2.3 million, respectively, and these amounts are recognized as a liability under other deferred liabilities in the Company’s Consolidated Statements of Financial Position.
Goodwill and Goodwill Impairment. Goodwill represents the excess of purchase price and related costs over the value assigned to the net identifiable assets of businesses acquired. The Company accounts for goodwill under the provisions of SFAS 141, “Business Combinations,” and SFAS 142, “Goodwill and Other Intangible Assets.” SFAS 141 addresses financial accounting and reporting for all business combinations and requires that all business combinations entered into after June 2001 be recorded under the purchase method. This statement also addresses financial accounting and reporting for goodwill and other intangible assets acquired in a business combination at acquisition. SFAS 142 addresses financial accounting and reporting for intangible assets acquired individually or with a group of other assets at acquisition. This statement also addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition.
The Company is required to perform impairment tests on its goodwill annually or at any time when events occur which could impact the value of the Company’s business segments. If an impairment test of goodwill shows that the carrying amount of the goodwill is in excess of the fair value, a corresponding impairment loss would be recorded in the Consolidated Statements of Operations.
The annual impairment tests for 2006 and 2005 were performed for the Company’s business segments and indicated that there was no impairment of goodwill.
During 2004, it was determined that all of the goodwill associated with the Company’s IT services business was impaired. The impairment charge was a result of the Company’s decision to exit the residential portion of its ISP operation. All of the goodwill for the Company’s IT services business was related to the residential ISP operation. The $0.2 million before-tax charge for impairment of goodwill is reflected in the Company’s Consolidated Statements of Operations in operating expenses. The 2004 annual goodwill impairment test was also performed for each of the Company’s other business segments and indicated that there was no impairment of goodwill.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
The following table summarizes changes in the carrying amount of goodwill for the past two years:
Unamortized Debt Expense. The Company defers expenses incurred in connection with the issuance of debt and amortizes these deferred expenses over the terms of the debt. If the underlying debt is retired or refinanced, any unamortized expenses are charged to expense in the Company’s Consolidated Statements of Operations, except in situations where the debt was specifically allocated to the Company’s Gas Distribution Business. In instances when debt allocated specifically to the Gas Distribution Business is refinanced, any unamortized expenses are deferred as a regulatory asset and amortized over the term of the new debt.
Customer Advance Payments. The Company receives advance payments from customers who sign up for the Company’s budget payment program. This program is designed so customers can pay their estimated annual gas charges in equal monthly payments. As a result, customers make advance payments during the non-heating season when consumption and charges are generally low, and then utilize these advance payments to pay for a portion of their gas bills during the heating season, when consumption and charges are generally high. Customer advance payments also include deposits the Company receives from customers to cover customer credit risk.
Revenue Recognition. The Gas Distribution Business bills monthly on a cycle basis and follows the utility industry practice of recognizing accrued revenue for services rendered to its customers but not billed at month end. Gas sales revenue is comprised of three components: (i) monthly customer service fees; (ii) volumetric distribution charges; and (iii) volumetric gas commodity charges. Monthly customer service fees represent fixed fees charged to customers. Distribution charges are charged to customers based on the volume of gas they consume. Gas commodity charges represent the cost of gas consumed by customers. As discussed in more detail in the Cost of Gas section below, the Company generally does not earn any income on the gas commodity charge portion of customer rates.
The Company’s other businesses recognize revenues in the period that services are rendered or products are delivered to customers.
Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers. The Company’s gas distribution area regulated by the MPSC operates with an MPSC-approved gas cost recovery (“GCR”) pricing mechanism. The Alaska-based gas distribution operation (“ENSTAR”) has an RCA-approved gas cost adjustment (“GCA”) pricing mechanism, which is similar to the GCR pricing mechanism. Both of these pricing mechanisms (hereinafter referred to as “GCR” pricing mechanisms) are designed so that, in the absence of any cost disallowances, the Company’s cost of gas purchased is passed-through to the Company’s customers on a dollar-for-dollar basis and, therefore, the Company does not recognize any income on the gas commodity charge portion of customer rates.
The GCR pricing mechanisms allow for the adjustment of rates charged to customers for increases and decreases in the cost of gas purchased by the Company for sale to customers. In the Company’s gas distribution area regulated by the MPSC, the GCR pricing mechanism is subject to an MPSC review of the Company’s GCR gas purchase plans and actual gas purchases. A GCR gas purchase plan is filed annually with the MPSC by December 31 of each year for the upcoming April 1 to March 31 GCR period. A reconciliation case is filed by June 30 of each year to reconcile actual gas purchases during the previous April 1 to March 31 GCR period to the GCR gas purchase plan for the same period. Both the GCR gas purchase plan and the reconciliation case may involve MPSC reviews of Company actions and decisions and potential cost disallowances. From time to time, parties in GCR cases propose
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
cost disallowances, and those matters are litigated in the proceedings. The Company does not recognize potential cost disallowances until the Company determines that the cost disallowances are probable. Disallowed costs are expensed in the cost of gas but are not recovered in rates.
The Company’s gas service area regulated by the CCBC had been operating under a fixed gas charge program during 2004 and the first three months of 2005. Under that program the Company suspended its GCR pricing mechanism and utilized a fixed gas charge in the rates for customers located in its service area regulated by the CCBC (“CCBC-regulated customers”). The Company was able to offer this GCR suspension and fixed commodity rate mainly as a result of a gas supply agreement. Under this agreement, the gas supplier provided a significant portion of the Company’s natural gas requirements, and managed the Company’s natural gas supply and the supply aspects of transportation and storage operations for the Company’s gas distribution area regulated by the CCBC. During this time, the Company’s service area regulated by the CCBC was not operating under a GCR pricing mechanism and certain gas cost savings allowed under the terms of the gas supply and management agreement (which expired March 31, 2005) were retained by the Company.
However, beginning April 1, 2005, the Company once again began to use a GCR pricing mechanism in the service area regulated by the CCBC and, therefore, gas cost savings allowed under the terms of the gas supply and management agreement were no longer retained by the Company. The GCR pricing mechanism in the Company’s service territory regulated by the CCBC calls for the GCR rate to be revised monthly, to track and recover changes in the cost of natural gas purchased by the Company for use by CCBC-regulated customers. The annual GCR period in the Company’s service territory regulated by the CCBC runs from April 1 to March 31.
The annual GCR period in Alaska runs from January 1 to December 31. The GCR rate established by the RCA reflects the pricing mechanisms in certain long-term gas supply contracts approved by the RCA and recovers the cost of natural gas purchased by the Company under those contracts.
Under the GCR pricing mechanisms, the gas commodity charge portion of customers’ gas rates (which is also referred to as the “GCR rate”) for the Company’s Michigan service areas regulated by the MPSC may be adjusted upward on a quarterly basis and downward on a monthly basis if actual natural gas prices paid by the Company are significantly different than the prices set in the MPSC-approved GCR plan. The GCR rate for the Michigan service areas regulated by the CCBC may be adjusted upward or downward on a monthly basis. Any GCR rate adjustments for the MPSC and CCBC service areas cannot cause the GCR rate to exceed the maximum GCR rate established in the GCR plan for the 12-month GCR period in question. The GCR rate for Alaska is generally adjusted annually to reflect the estimated cost of gas purchased for the upcoming 12-month GCR period.
Any difference between actual allowed cost of gas purchased and the estimate for a particular GCR period is deferred as either a gas charge over- or under-recovery and included in customer GCR rates during the next GCR period. A gas charge over-recovery occurs when the estimated cost of gas exceeds the actual cost of gas purchased and is reflected in Amounts Payable to Customers in the current liabilities section of the Company’s Consolidated Statements of Financial Position. A gas charge under-recovery occurs when the actual cost of gas purchased exceeds the estimated cost of gas and is reflected in Gas Charges Recoverable from Customers in the current assets section of the Company’s Consolidated Statements of Financial Position. At December 31, 2006, the Company had $6.1 million recorded in current liabilities for Amounts Payable to Customers and $2.9 million recorded in current assets for Gas Charges Recoverable from Customers, under the GCR pricing mechanisms.
Self-Insurance. The Company is self-insured for health care costs up to $75,000 per subscriber annually. Insurance coverage is carried for risks in excess of this amount. The Company incurred self-insured health care expense of approximately $3.1 million, $2.4 million and $4.0 million for the years ended December 31, 2006, 2005 and 2004, respectively. Estimated claims incurred but not reported were $0.6 million as of December 31, 2006, and 2005, and are included in other current liabilities in the Consolidated Statement of Financial Position.
Income Taxes. The Company files a consolidated federal income tax return and income taxes are allocated among the Company’s subsidiaries and divisions based on their separate taxable income. Investment tax credits
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
(“ITC”) utilized in prior years for income tax purposes are deferred for financial accounting purposes and are amortized through credits to the income tax provision over the lives of the related property. For additional information, refer to Note 3.
Share-Based Compensation. In December 2004, the FASB issued SFAS 123 (revised 2004) - “Share-Based Payment” (“SFAS 123-R”). This standard supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and requires recognition of expense in the Company’s financial statements for the cost of share-based payment transactions, including stock option awards, based on the fair value of the award at the grant date. This standard also amends SFAS 95, “Statement of Cash Flows,” to require that excess tax benefits related to the excess of the share-based compensation deductible for tax purposes over the compensation recognized for financial reporting purposes be classified as cash inflows from financing activities rather than as a reduction of taxes paid in operating activities.
The Company adopted this standard on January 1, 2006, using the modified prospective method described in SFAS 123-R. Under this transition method, compensation expense recognized during 2006, included: (i) compensation expense for all share-based awards granted prior to, but not yet vested as of, December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation - Transition and Disclosure” (collectively “SFAS 123”); and (ii) compensation expense for all share-based awards granted after December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS 123-R. In accordance with the modified prospective method, results from prior periods have not been restated.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
Prior to the adoption of SFAS 123-R, the Company accounted for share-based compensation arrangements in accordance with SFAS 123. In accordance with SFAS 123, the Company chose to account for certain of its share-based compensation arrangements under APB 25 for purposes of determining net income but presented the pro forma disclosures required by SFAS 123. As a result, the Company’s net income (loss) as reported in its Consolidated Statements of Operations for periods prior to January 1, 2006, reflected compensation expense for certain of its share-based compensation arrangements calculated using the intrinsic value method provided for under the provisions and related interpretations of APB 25 rather than the fair value method provided for under SFAS 123. If all of the Company’s share-based compensation expense for periods prior to January 1, 2006, had been determined in a manner consistent with the provisions of SFAS 123, the Company’s net income (loss) available to common shareholders and related earnings (loss) per share would have been reduced to the pro forma amounts set forth in the table below:
As a result of adopting SFAS 123-R on January 1, 2006, the Company’s income before income taxes and net income available to common shareholders was $0.5 million and $0.3 million lower, respectively, for 2006, than if the Company had continued to account for share-based compensation under APB 25. The reductions in earnings reduced basic and diluted earnings per share by $0.01 for 2006. Refer to Note 4 for further information about the Company’s share-based compensation arrangements.
New Accounting Standards. In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109.” This interpretation clarifies the accounting for uncertainty in income taxes recognized in a Company’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a 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. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company does not expect that the interpretation will have a material impact on its consolidated financial position and results of operations.
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements.” SFAS 157 defines fair value, provides guidance for using fair value to measure assets and liabilities and expands disclosures about fair value measurements. SFAS 157 applies to other standards that require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. This statement is effective for financial
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is in the process of evaluating the effect of this statement on its consolidated financial position and results of operations.
In September 2006, the FASB issued SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which changes the financial reporting for defined benefit pension and postretirement plans. SFAS 158 requires companies to, among other things, recognize in their consolidated statements of financial position the funded status of their defined benefit postretirement plans measured as the difference between the fair value of plan assets and the related benefit obligation. For a pension plan, the benefit obligation would be the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation would be the accumulated postretirement benefit obligation. SFAS 158 also requires companies to recognize as a component of other comprehensive income, net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period but, pursuant to SFAS 87 and 106, are not recognized as components of net periodic benefit cost in the consolidated statement of operations. Amounts recognized in accumulated other comprehensive income would be adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of SFAS 87 and 106.
The Company adopted SFAS 158 on December 31, 2006. In addition, and as discussed below, the Company also adjusted the funded status of certain of its benefit plans from accumulated comprehensive income to regulatory assets. As a result of the adoption of SFAS 158, the Company’s consolidated statement of financial position at December 31, 2006, was affected as follows: (i) accrued pension and other postretirement benefit costs increased by approximately $23.6 million; (ii) prepaid pension and other postretirement benefit costs increased by approximately $1.8 million; (iii) intangible assets decreased by approximately $0.4 million; (iv) common shareholders’ equity (specifically, accumulated comprehensive income) decreased by approximately $11.1 million; and (v) the deferred income tax liability decreased by approximately $11.2 million. The Company reached an agreement to modify its Bank Credit Agreement, as defined in Note 5, to exclude the impact on shareholders’ equity of adopting SFAS 158 from certain financial covenants. As noted above, the Company also established a regulatory asset for the funded status of certain of its pension and other postretirement benefit plans, net of certain tax benefits. As a result of establishing this regulatory asset on December 31, 2006, the Company’s consolidated statement of financial condition was affected as follows: (i) regulatory assets increased by $26.9 million; (ii) common shareholders’ equity (specifically, accumulated comprehensive income) increased by approximately $15.9 million; and (iii) the deferred income tax liability increased by approximately $11.0 million. For further information, refer to Note 8.
In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. If the Company chooses to elect the fair value option for an item, the Company would recognize unrealized gains and losses associated with changes in the fair value of the item over time. SFAS 159 will also require disclosures for items for which the fair value option has been elected. SFAS 159 will be effective for the Company on January 1, 2008. The Company is currently evaluating the impact of choosing to elect the fair value option for any of its financial instruments or other items on its financial position, cash flows, and results of operations.
Statements of Cash Flows. For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid investments purchased with original maturities of three months or less to be cash and cash equivalents.
On April 24, 2006, the Company issued 865,028 shares of the Company’s Common Stock and paid $5.0 million in cash to a holder of the Company’s Preferred Stock, in exchange for 50,884 shares of Preferred Stock, which were retired. On May 26, 2006, the Company issued 689,996 shares of the Company’s Common Stock and paid $7.6 million in cash to another holder of the Company’s Preferred Stock, in exchange for 59,900 shares of Preferred
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 1.
Company Description and Significant Accounting Policies (continued)
Stock, which were retired. The components of these transactions that do not involve the exchange of cash are not reflected in the Company’s Consolidated Statements of Cash Flows.
Dividends associated with the Company’s Convertible Preference Stock (“CPS”) were $0.9 million and $3.2 million in 2005 and 2004, respectively. These dividends were paid in additional shares of CPS, or what is commonly referred to as stock dividends or payment-in-kind dividends. The issuance of stock dividends is a non-cash financing activity and therefore is not reflected in the Consolidated Statements of Cash Flows. Refer to Note 4 for further information regarding the issuance of stock dividends on the CPS and the subsequent repurchase of the CPS in March 2005.
Supplemental cash flow information for the years ended December 31, 2006, 2005, and 2004, is summarized in the following table:
Note 2.
Regulatory Matters
MPSC. On May 25, 2006, the Company filed a request with the MPSC seeking authority to increase the Company’s base rates for service to customers in the service area regulated by the MPSC (the “MPSC Division”) by approximately $18.9 million. As part of its filing, the Company also proposed to change various aspects of the Company’s rate design (meaning the way in which the costs of providing service to customers are collected in base rates and other rates and charges). These proposed rate design changes included: (i) elimination of a consumption-based distribution charge for residential customers, to be replaced by a fixed monthly service charge (which would include the current fixed monthly customer charge) for those customers or, in the alternative, to collect a fixed monthly customer charge and a fixed distribution charge; (ii) collection of lost and unaccounted for (“LAUF”) gas costs in the gas cost recovery (“GCR”) rate or, in the alternative, an annual “true-up” of LAUF gas costs allowed by the MPSC in base rates and the Company’s actual LAUF gas costs; (iii) an annual “true-up” of the uncollectible (or bad debt) expense allowed by the MPSC in base rates and the Company’s actual uncollectible expense; (iv) the recovery of certain Company-sponsored or -funded conservation program costs; and (v) the recovery of the capital-related costs associated with the replacement of certain bare steel mains and storage field compressors. As an alternative, the Company proposed that the volumetric billing determinant for residential rates be set at a level that more closely approximated current customer usage, on a normalized basis.
In July 2006, the MPSC set a schedule for the proceeding on this filing and, based on that schedule, the Company had expected the MPSC to decide the case by mid- to late-Spring 2007. On December 29, 2006, the parties to the proceeding reached a settlement and filed it with the MPSC. The MPSC met on January 9, 2007, approved the proposed settlement, and issued an order for the implementation of the new rates for service rendered on and after January 10, 2007.
The order approving the settlement revised base rates, which are intended to recover the Company’s non-gas costs of providing service. These revised base rates are estimated to produce total annual revenues of approximately $90.5 million. This total annual revenue figure includes an estimated increase in annual base rate revenues of approximately $12.65 million based on adjusted 2005 test year data. However, the Company expects that, based on the Company’s current projections for 2007 residential use per customer, the revised rates would result in an increase of approximately $10.55 million in annualized base rate revenue. This base rate increase does not affect or include the cost of natural gas used by customers, which fluctuates with changes in market prices, and is passed
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2.
Regulatory Matters (continued)
through to customers via the GCR component of customer rates as discussed in Note 1 under the caption, “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers.”
With the exceptions discussed below, none of the changes to rate design proposed by the Company were part of the MPSC-approved settlement. The consumption-based distribution charge for residential customers was not eliminated; however, the fixed monthly customer charge was increased from $9.50 to $10.00 per month, increasing the portion of fixed costs recovered in a fixed charge. The Company’s proposals for recovery of LAUF gas costs and an annual true-up for uncollectible expense were not included in the MPSC-approved settlement, nor were the conservation program or the recovery of the capital-related costs associated with the replacement of certain bare steel mains and storage field compressors.
The MPSC order did address the continuing decline in residential customer consumption by changing a key billing element included in residential base rates. In the MPSC order issued in the Company’s previous rate case proceeding in March 2005, residential base rates were set using annual customer usage of about 113 Mcf of natural gas. In the MPSC order issued on January 9, 2007, residential base rates were set using annual customer usage of 96 Mcf of natural gas. This reduction in the use per residential customer billing determinant recognizes that residential customer consumption has been steadily declining and sets base rates using an annual volume of gas consumption per customer that may be reasonably expected to be sold in a year with normal weather under current consumption patterns.
As a part of the settlement approved in the MPSC order, the Company also agreed not to file for base rate increases for the Company’s MPSC Division customers until after January 1, 2008.
In December 2004, the Company filed a base rate increase request totaling $11.65 million with the MPSC. On March 29, 2005, the MPSC approved a proposed settlement, which, at the time of settlement, was expected to produce an additional $7.1 million in annual revenue from customers in the MPSC Division. Increases in the fixed customer charge for several commercial and industrial customer classes and the increase in fees for certain services mitigated some of the effect of consumption and weather on the Company’s revenues. The rate adjustments authorized by this settlement became effective on March 30, 2005.
The Company also is involved in various GCR proceedings before the MPSC, which are described in Note 1 under the caption, “Cost of Gas, Gas Charges Recoverable from Customers, and Amounts Payable to Customers.” The Company seeks to end its GCR period ending on March 31 of each year with no significant under-recovery or over-recovery of costs incurred to purchase gas for sale to customers. However, if actual gas prices near the end of the GCR period change significantly from prices in the GCR plan, a significant under-recovery or over-recovery could occur.
On October 14, 2004, the MPSC initiated a generic proceeding involving all Michigan electric and gas utilities to review SFAS 143, “Accounting for Asset Retirement Obligations,” Federal Energy Regulatory Commission Order No. 631, “Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations,” and related accounting and ratemaking issues. As directed by the MPSC, the Company filed responses, in the form of testimony, to various questions raised by the MPSC regarding the Company’s accounting practices for property retirements, including the cost of removal. Among other things, this proceeding involves an examination of possible changes in accounting for property retirements, for rate making purposes. On August 8, 2006, the Administrative Law Judge issued a Proposal for Decision that FAS 143 and FERC Order 631 be adopted for accounting purposes but not ratemaking purposes, and that the MPSC give due consideration to the revision of the traditional method of calculating removal costs. The matter awaits a decision by the MPSC.
CCBC. In November 2004, the Company filed a base increase request totaling $5.07 million with the CCBC. In February 2005, the CCBC approved a proposed settlement, effective for the first customer billing cycle in April 2005, which, at the time of settlement, was expected to produce an additional $3.55 million in annual revenue, with additional annual revenue increases of $150,000 to be put into effect beginning in April of 2006, and 2007, respectively, subject to certain conditions, including the Company’s making annual contributions to assist low
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2.
Regulatory Matters (continued)
income customers in paying their bills for service. With certain exceptions, the Company has agreed not to request a further base rate increase to be effective before April 1, 2008.
The GCR rate for the approximately 37,000 customers in the service territory regulated by the CCBC is revised monthly, to track and recover changes in the cost of natural gas purchased by the Company for use by CCBC-regulated customers. The Company seeks to end its GCR period (which ends on March 31 of each year) with no significant gas charge under-recovery or over-recovery.
In May 2006, the Company and the CCBC filed a joint application with the MPSC requesting that the MPSC assume jurisdiction over the service area currently regulated by the CCBC. The joint application asked the MPSC to approve the CCBC tariff, rates, charges and conditions of service that are currently in effect. In October 2006, the Company and the CCBC submitted an amended joint application to address certain rate and procedural issues. The amended joint application provides that the Company will file a GCR gas purchase plan similar to the GCR gas purchase plan filed annually with the MPSC for the Company’s gas distribution service area regulated by the MPSC and a GCR tariff. The Company expects a decision from the MPSC in this matter by mid-year 2007. The Company is unable to predict, however, when the MPSC will act on this filing or what the outcome might be.
RCA. The RCA issued an order dated June 16, 2005, requiring ENSTAR to file a revenue requirement and cost of service study (including rate design data) with the RCA by June 6, 2008 (using a test year ended December 31, 2007). In addition, ENSTAR is required to file a depreciation study of utility plant (as of December 31, 2006) by June 1, 2007. These filings also will include the Company’s Alaska Pipeline Company (“APC”) subsidiary.
On or about April 1, 2006, the Company received a letter from Aurora Gas LLC (“Aurora Gas”) regarding the Moquawkie Contract. In that letter, Aurora Gas asserted that, after April 1, 2006, continued production of gas by Aurora Gas for the Company would be “Not Economic” as that term is defined in the Moquawkie Contract, permitting Aurora Gas to suspend deliveries to the Company effective October 1, 2006.
The Moquawkie Contract provides that Aurora Gas will supply a portion of the Company’s gas requirements for ENSTAR through 2014. Aurora Gas was required to deliver up to 1.8 Bcf of gas in 2006. This requirement declines annually until the projected final year requirement of 0.2 Bcf in 2014. The total remaining commitment at the end of 2006 was approximately 5.9 Bcf.
On October 1, 2006, Aurora Gas suspended deliveries of gas to the Company under the Moquawkie Contract. The Company has obtained substitute gas from alternative sources to replace Moquawkie Contract volumes Aurora Gas has not delivered. The cost of such gas is higher than the cost of gas under the Moquawkie Contract. In its annual GCR filing for 2007, the Company filed with the RCA to recover from its customers the higher cost of the substitute gas. The Company also told the RCA that, if the Company recovers damages from Aurora Gas relating to the suspension of Moquawkie Contract deliveries, the Company intends to credit any recovery, net of the Company’s costs, against the gas costs borne by its Alaska customers. The RCA approved the Company’s 2007 GCR, as filed, in December 2006.
In 2005, the Company entered into a gas supply contract with Marathon Oil Company (“Marathon”) to supply a portion of the needs of the Company’s Alaska customers from 2009 through 2017 (the “2005 Marathon Contract”). In November 2005, the Company submitted the 2005 Marathon Contract to the RCA for approval. On September 28, 2006, the RCA rejected the 2005 Marathon Contract, holding, among other things, that the Company had not met its burden of demonstrating that gas supplies to be provided under the contract were reliable and that the contract price (which was proposed to be tied to an index) was reasonable. Parties to the case, including the Company, filed motions for reconsideration and/or clarification of the RCA order. In December 2006, the RCA issued an order that granted, in part, the petitions for reconsideration, but the RCA did not approve the 2005 Marathon Contract. Marathon exercised its right to terminate the 2005 Marathon Contract in January 2007. RCA members subsequently issued dissenting and concurring opinions in this matter, explaining their positions in more detail than appeared in earlier orders.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 2.
Regulatory Matters (continued)
Regulatory Assets and Liabilities. The Gas Distribution Business is subject to the provisions of SFAS 71. The provisions of SFAS 71 allow the Company to defer expenses and income as regulatory assets and liabilities in the Consolidated Statements of Financial Position when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statements of Operations by an unregulated entity. These deferred regulatory assets and liabilities are then included in the Consolidated Statements of Operations in the periods in which the same amounts are reflected in rates. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Statements of Financial Position and included in the Consolidated Statements of Operations for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as extraordinary items. Criteria that give rise to the discontinuance of SFAS 71 include (i) increasing competition that restricts the ability of the Gas Distribution Business to charge prices to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Company’s review of these criteria currently supports the continuing application of SFAS 71.
The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Statements of Financial Position, as well as the remaining period, as of December 31, 2006, over which the Company expects to realize or settle the assets or liabilities.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 3.
Income Taxes
SFAS 109. The Company accounts for income taxes in accordance with SFAS 109, “Accounting for Income Taxes.” SFAS 109 requires an annual measurement of deferred tax assets and deferred tax liabilities based upon the estimated future tax effects of temporary differences and carry-forwards.
Reconciliation of Statutory Rate to Effective Rate. The table below provides a reconciliation of the difference between the Company’s provision for income taxes and income taxes computed at the statutory rate.
Deferred Income Taxes. Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s financial statements. At December 31, 2006, and 2005, there was a valuation allowance of $0.3 million and $0.4 million, respectively, recorded against deferred tax assets. The Company also has an estimated net operating loss (“NOL”) carryforward for federal tax purposes of $84 million at December 31, 2006, of which an $19 million expires in 2022, $49 million expires in 2023 and $16 million expires in 2024. The Company’s ability to utilize its NOLs is limited by the Internal Revenue Code. However, the Company currently expects that it will achieve enough taxable income in future years to utilize its NOLs prior to their expiration.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 3.
Income Taxes (continued)
The table below shows the principal components of the Company’s deferred tax assets (liabilities).
Note 4.
Capitalization
Common Shareholders’ Equity. On April 24, 2006, the Company issued 865,028 shares of the Company’s Common Stock and paid $5.0 million in cash to a holder of the Company’s Preferred Stock, in exchange for 50,884 shares of Preferred Stock, which were retired. On May 26, 2006, the Company issued 689,996 shares of the Company’s Common Stock and paid $7.6 million in cash to another holder of the Company’s Preferred Stock, in exchange for 59,900 shares of Preferred Stock, which were retired. These transactions resulted in a gain of $0.2 million, which is reflected in dividends on the Preferred Stock in the Company’s Consolidated Statement of Operations for 2006. The components of these transactions that do not involve the exchange of cash are not reflected in the Company’s Consolidated Statements of Cash Flows.
On August 15, 2005, the Company completed an offering of 4,945,000 shares of Common Stock, at a public offering price of $6.32 per share. The aggregate gross proceeds of the offering were $31.3 million, with net proceeds of approximately $30.0 million after deducting underwriting discounts and commissions. The proceeds from the completion of this offering were used to redeem all of the Company’s outstanding 10.25% Series A Subordinated Debentures due 2040 (“10.25% Subordinated Notes”) held by the Company’s unconsolidated capital trust subsidiary, SEMCO Capital Trust I (the “Trust”), as discussed below.
During 2006 and 2005, the Company issued 9,750 shares and 176,583 shares, respectively, of its restricted Common Stock to members of the Company’s Board of Directors (“Board”) as part of the compensation for their services. The restrictions on 7,833 of those shares issued in 2005 were waived due to the immediate retirement eligibility of the two individuals to whom those shares were granted. Another 7,000 shares were forfeited in 2006 as
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4.
Capitalization (continued)
a result of the retirement of a member of the Board. The restricted shares of Common Stock vest over periods of up to three years. The value of the restricted Common Stock at the time of issuance is added to the Company’s common shareholders equity, and there is an offsetting amount, which is also recorded in common shareholders’ equity, that represents the unearned compensation associated with the restricted Common Stock. This unearned compensation is accreted to compensation expense over the period that the restricted stock is earned, which is typically the vesting period.
During 2006, 2005, and 2004, the Company issued approximately 36,000, 40,000 and 192,000 shares, respectively of its Common Stock to the Company’s Direct Stock Purchase and Dividend Reinvestment Plan (“DRIP”) to meet the dividend reinvestment and stock purchase requirements of DRIP participants.
The Company issued approximately 161,000, 144,000 and 145,000 shares of Common Stock to certain of the Company’s employee benefit and Director deferred compensation plans in 2006, 2005, and 2004, respectively. Of the issuances, related to 2005 and 2004, approximately 6,000, and 9,000 shares are related to Director deferred compensation. Refer to Note 9 for further information on Directors’ stock-based compensation.
As discussed below under “Convertible Preference Stock and Stock Warrants,” in March 2004, warrants to purchase 905,565 shares of Common Stock (“Warrants”) were issued in conjunction with the issuance of CPS. The net proceeds associated with the Warrants, approximately $0.7 million, were included in capital surplus in the common shareholders’ equity section of the Consolidated Statements of Financial Position at the time of their issuance. In March 2005, the Company paid $2.1 million to repurchase these Warrants. The $2.1 million paid to repurchase the Warrants is reflected in common shareholders’ equity as a decrease in capital surplus.
The Company’s common shareholders’ equity at December 31, 2006, and 2005, included accumulated comprehensive losses of $0.6 million and $9.1 million, respectively. The following table provides the components of the accumulated comprehensive losses, at December 31, 2006 and 2005, net of income taxes (in thousands):
Convertible Preference Stock and Stock Warrants. During 2004, the Company issued through a private placement, $50 million of CPS and Warrants to K-1 GHM, LLLP, an affiliate of a private equity firm, k1 Ventures Limited (“K-1”). The private placement included 50,000 shares of CPS and Warrants to purchase 905,565 shares of the Company’s Common Stock. The net proceeds from this issuance were approximately $46.3 million. The portion of the net proceeds associated with the Warrants, approximately $0.7 million, was included in the common shareholders’ equity section of the Consolidated Statements of Financial Position as an increase in capital surplus.
On March 8, 2005, the Company reached an agreement with K-1 to repurchase all of the outstanding CPS shares (52,543 shares) and Warrants held by K-1. On March 15, 2005, the Company completed this repurchase. The aggregate repurchase price under the agreement was $60 million. Approximately $57.9 million of the repurchase price related to the CPS and the remainder, approximately $2.1 million, related to the Warrants. The repurchase price for the CPS included a premium over the book value of the CPS of approximately $8.2 million. The $8.2 million repurchase premium payment is reflected in the Company’s Consolidated Statements of Operations for the year ended December 31, 2005. The $2.1 million paid to repurchase the Warrants is included in capital surplus in the common shareholder’s equity section of the Consolidated Statements of Financial Position. During 2005 and 2004, the Company paid stock dividends on the CPS of 777 and 1,766 additional shares of CPS, respectively.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4.
Capitalization (continued)
5% Series B Convertible Cumulative Preferred Stock. On March 15, 2005, concurrent with and in order to fund the repurchase of CPS and Warrants from K-1, the Company completed the offering of 325,000 shares of 5% Series B Convertible Cumulative Preferred Stock (“Preferred Stock”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933 (the “Act”) and to persons in offshore transactions in reliance on Regulation S under the Act. The gross proceeds from this offering were approximately $65.0 million.
The Company also granted the initial purchasers a 30-day option to purchase up to an additional 25,000 shares of Preferred Stock in connection with the offering. On March 22, 2005, the sale of an additional 25,000 shares of Preferred Stock was completed pursuant to the exercise of the option by the initial purchasers. The gross proceeds from the sale of the additional shares were approximately $5.0 million.
Of the proceeds from this combined offering, $60 million was used to fund the repurchase of CPS and Warrants from K-1. The remaining proceeds were used to redeem $10.3 million of the Company’s 10.25% Subordinated Notes, held by the Trust, on April 29, 2005. The Trust, in turn, used the proceeds to redeem 400,000 shares of its 10.25% Cumulative Trust Preferred Securities and 12,371 shares of its common securities.
The Preferred Stock is convertible at the holder’s option at any time at an initial conversion rate of 26.1428 shares of the Company’s Common Stock per share of Preferred Stock ($200 liquidation preference per share), which represents an initial conversion price of approximately $7.65 per share of Common Stock. In April and May of 2006, the Company repurchased and retired 50,884 and 59,900 shares, respectively, of Preferred Stock, such that there were 239,216 shares of Preferred Stock outstanding at December 31, 2006. For further information on these transactions, see the section above captioned “Common Shareholder’s Equity.”
The Company may redeem the Preferred Stock for cash after February 20, 2010, at an initial redemption price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends to the date of redemption. The Preferred Stock is mandatorily redeemable for cash on February 20, 2015, at a redemption price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends to the date of redemption.
Holders of shares of the Preferred Stock are entitled to receive cumulative annual cash dividends of $10 per share, payable quarterly in cash on each February 15, May 15, August 15 and November 15. Dividends are paid in arrears on the basis of a 360-day year consisting of twelve 30-day months. Dividends on the Preferred Stock accumulated from the date of issuance and compound quarterly. Dividends paid in 2006 and 2005 on the dividend payment dates were as follows:
If certain specified “fundamental changes” involving the Company occur prior to February 20, 2010, the Company may be required to pay a make-whole premium on the Preferred Stock converted in connection with the fundamental change. The make-whole premium will be payable in shares of the Company’s Common Stock or the consideration into which the Common Stock has been converted or exchanged in connection with the fundamental
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4.
Capitalization (continued)
change. The amount of the make-whole premium, if any, will be based on the Common Stock price and the effective date of the fundamental change. A “fundamental change” involving the Company will be deemed to have occurred if (i) certain transactions occur as a result of which there is a change of control of the Company, or (ii) the Company’s Common Stock ceases to be listed on a national securities exchange or quoted on The Nasdaq National Market or another established automated over-the- counter trading market in the United States.
Registration Statements. On April 11, 2005, the Company filed a universal shelf registration statement on Form S-3 with the SEC to register an aggregate of $150 million of various securities, which was declared effective by the SEC on June 14, 2005. Subsequent to the effectiveness of this registration statement, the Company completed a Common Stock offering of $31.3 million under the shelf registration statement, leaving $118.7 million of securities available for possible future issuances under this registration statement. In addition, and as discussed in more detail below, on May 26, 2005, the Company filed a resale shelf registration statement with the SEC, in compliance with its obligations under a registration rights agreement entered into at the time of the issuance of the Preferred Stock. This resale registration statement relates to the resale of shares of the Preferred Stock and to shares of Common Stock issuable upon conversion of the Preferred Stock and was declared effective by the SEC on August 12, 2005.
Company Obligated Mandatorily Redeemable Trust Preferred Securities. The Company had Company-obligated mandatorily redeemable trust preferred securities that were issued by its capital trust subsidiaries (“Trust Preferred Securities”). These trusts were established for the sole purpose of issuing Trust Preferred Securities to the public and lending the gross proceeds, including the proceeds from the Company’s common equity investment, to the Company. The sole assets of the capital trusts were debt securities of the Company with terms similar to the terms of the related Trust Preferred Securities. The Trust Preferred Securities had characteristics of both debt and equity. In accordance with the provisions of SFAS 150, the dividends incurred on these securities subsequent to July 1, 2003 were reflected in “interest expense.”
On April 29, 2005, the Company used a portion of the proceeds it received from the issuance of its Preferred Stock to redeem $10.3 million of the 10.25% Subordinated Notes held by the Trust. Concurrently, the Trust used the proceeds it received from the redemption of the 10.25% Subordinated Notes to redeem 400,000 Trust Preferred Securities at a redemption price of $25.00 per security, for a total principal payment of $10.0 million. The Trust also used a portion of the proceeds to redeem $0.3 million of the Company’s common equity investment in the Trust, representing 12,371 common securities of the Trust.
On September 14, 2005, the Company used the proceeds it received from the sale of 4,945,000 shares of its Common Stock to redeem the remaining $30.9 million of the 10.25% Subordinated Notes held by the Trust. Concurrently, the Trust used the proceeds it received from the redemption of the 10.25% Subordinated Notes to redeem the remaining 1.2 million Trust Preferred Securities at a redemption price of $25.00 per security, for a total principal payment of $30.0 million. The Trust also used a portion of the proceeds to redeem the remaining $0.9 million of the Company’s common equity investment in the Trust, representing 37,114 common securities of the Trust.
As a result of redemptions during 2005, at December 31, 2005 and 2006, the Company had no common equity investment in the trusts, the trusts had no outstanding Trust Preferred Securities, and the Company had no outstanding debt due to the trusts.
Long-Term Debt. On October 31, 2006, the Company entered into a bank term loan agreement in the amount of $55 million (the “Bank Term Loan”). The Bank Term Loan matures on June 30, 2016, and is callable at any time at the option of the Company. Interest on the Bank Term Loan is payable at variable rates based on LIBOR plus an applicable margin. The applicable margin is fixed for the first 4 years of the Bank Term Loan and then increases by a fixed amount for the remaining term of the Bank Term Loan. As a result, the Bank Term Loan is being accounted for as increasing-rate debt. The Company expects to repay this Bank Term Loan during the 4-year period following its issuance date. In accordance with the applicable accounting requirements for increasing-rate debt, interest and debt
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4.
Capitalization (continued)
issuance costs associated with this Bank Term Loan are being expensed assuming that the term of the Bank Term Loan is 4 years.
The Company received the proceeds of the Bank Term Loan on November 29, 2006. The proceeds were used to retire a portion of the $59.5 million principal amount outstanding of the Company’s 8% Senior Notes due 2016. On November 1, 2006, the Company called for redemption of the $59.5 million of 8% Senior Notes due 2016, at a redemption price equal to 100% of the principal amount plus accrued interest. The notes were redeemed on November 30, 2006.
In November 2006, the Company entered into two interest rate swap agreements with a financial institution in order to hedge the LIBOR component of the interest payments on a portion of the Company’s $55 million Bank Term Loan. The first interest rate swap agreement hedges the LIBOR component of the interest payments on $20 million of the $55 million Bank Term Loan for the period February 27, 2007, through February 27, 2008. The second interest rate swap agreement hedges the LIBOR component of the interest payments on another $20 million of the $55 million Bank Term Loan for the period February 27, 2007, through February 27, 2009. The swap agreements effectively convert the variable or floating interest rate on the note to a fixed interest rate and are being accounted for as cash flow hedges. On a quarterly basis, for each swap, the Company pays the counterparty a fixed interest rate (5.1% on the first interest rate swap and 4.9% on the second interest rate swap) and receives payments based on a floating interest rate based on LIBOR. Refer to Note 7 for additional information.
In November 2005, the Company’s $15.0 million of outstanding 6.5% Senior Notes matured and were redeemed at par. The Company utilized its Bank Credit Agreement to finance this redemption. For further information on the Bank Credit Agreement, refer to Note 5 of the Notes to the Consolidated Financial Statements.
On April 29, 2005, the Company redeemed $10.3 million of the 10.25% Subordinated Notes held by the Trust. On September 14, 2005, the Company redeemed the remaining $30.9 million of the 10.25% Subordinated Notes held by the Trust. The redemptions were funded from proceeds received from the sale of Preferred Stock and Common Stock in 2005, as previously discussed in this Note under the caption “Company Obligated Mandatorily Redeemable Trust Preferred Securities.”
In January 2004, the Company entered into an interest rate swap agreement with a financial institution in order to hedge $50 million of its $150 million 7.125% senior unsecured notes due 2008. The swap agreement, which covers these notes through maturity, effectively converts the fixed interest rate on these notes to a floating interest rate and is being accounted for as a fair value hedge. On a semi-annual basis, the Company pays the counterparty a floating interest rate based on LIBOR plus a spread of 375 basis points and receives payments based on a fixed interest rate of 7.125%. Refer to Note 7 for additional information.
At December 31, 2006, there were no annual sinking fund requirements for the Company’s existing debt over the next five years. The Company has $185 million of long-term debt maturing over the next five years as follows (in millions):
Notwithstanding the debt maturity schedule above, the indentures, under which long-term debt of $150 million due 2008 and $200 million due 2013 was issued, contain provisions that provide that upon the occurrence of a change of control of the Company, the Company shall make an offer to repurchase all or any part of the notes at a purchase price equal to 101% of the aggregate principal amount of the notes. In addition, under the terms of the agreements which govern the Bank Term Loan and Bank Credit Agreement, an event of default would occur upon a change of control of the Company. In such an event, the lenders may declare any outstanding amounts immediately
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4.
Capitalization (continued)
due and payable. A change of control of the Company would occur upon the closing of the transaction described in Note 15.
Note 5.
Short-Term Borrowings
The Company has an unsecured $120.0 million revolving bank credit agreement, which expires on September 15, 2008 (the “Bank Credit Agreement”). Interest paid under the terms of the Bank Credit Agreement is at variable rates, which are based on LIBOR or prime lending rates, plus applicable margins. LIBOR-based borrowings are permitted for periods ranging from two weeks to one, two, three or six months. At December 31, 2006, the Company was utilizing $58.5 million of the borrowing capacity available under the Bank Credit Agreement, leaving approximately $61.5 million of the borrowing capacity unused. The $58.5 million of capacity being used consisted of $7.8 million of letters of credit and $50.7 million of borrowings. These amounts will change from time to time reflecting the Company’s then current working capital needs.
In the fourth quarter of 2006, the Company established three unsecured discretionary bank lines of credit (“Lines of Credit”) totaling $37.5 million consisting of:
The banks are not obligated to make any advances under these Lines of Credit and may at any time, without notice, in their sole and absolute discretion, refuse to make advances to the Company. Interest paid under the Lines of Credit is at variable rates, which are based upon prime lending rates or rates quoted by the banks. The Company anticipates that, under these arrangements with various lenders, at any given time, its total outstanding advances under the current Lines of Credit, collectively, will not exceed $15 million at the end of each quarter. At December 31, 2006, the Company was utilizing $15 million of the borrowing capacity available under these Lines of Credit.
(a)
The total amount that would be permitted to be outstanding, through a combination of utilizing the $120 million available to the Company from its Bank Credit Agreement and the $37.5 million of total credit potentially available to the Company from Lines of Credit, is $135 million.
Covenants in the Company’s Bank Credit Agreement require that the Company maintain at the end of each calendar quarter, a minimum consolidated net worth of $225.0 million, adjusted annually by 50% of consolidated net income, if positive, plus 100% of the proceeds of each new capital offering conducted by the Company or any of its subsidiaries on or after June 30, 2005, net of issuance costs, less the aggregate principal amount of any junior capital which is retired, prepaid or redeemed in connection with a new capital offering. At December 31, 2006, the
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 5.
Short-Term Borrowings (continued)
required minimum net worth was $228.8 million. In addition, the Bank Credit Agreement requires the Company to maintain, at the end of each fiscal quarter, a minimum interest coverage ratio of not less than 1.25 to 1 through September, 30, 2007, and not less than 1.30 to 1 thereafter, and a maximum leverage ratio of not more than 65%. The Company’s failure to comply with any of its financial covenants may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the Bank Credit Agreement, the Lines of Credit, or the indentures governing its outstanding debt issuances that contain cross-acceleration or cross-default provisions. In such a case, there can be no assurance that the Company would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on the Company’s business, results of operation, liquidity and financial condition.
Note 6.
Financial Instruments
The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:
Cash, Cash Equivalents, Accounts Receivables, Payables and Notes Payable. The carrying amount approximates fair value because of the short maturity of those instruments.
Long-Term Debt. The fair values of the Company’s long-term debt are estimated based on quoted market prices for the same or similar issues. The table below shows the estimated fair values of the Company’s long-term debt as of December 31, 2006, and 2005:
Note 7.
Risk Management Activities and Derivative Transactions
The Company’s business activities expose it to a variety of risks, including commodity price risk and interest rate risk. The Company’s management identifies risks associated with the Company’s business and determines which risks it wants to manage with financial instruments and which type of instruments it should use to manage those risks.
The Company records all derivative instruments it enters into under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS 137, SFAS 138 and SFAS 149, which were amendments to SFAS 133 (hereinafter collectively referred to as “SFAS 133”). SFAS 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the statement of financial position, as either an asset or liability, measured at its fair value. SFAS 133 also requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives designated as cash flow hedges, changes in fair value are recorded in comprehensive income for the portion of the change in value of the derivative that is an effective hedge. Any ineffective portion of the change in fair value would be recorded as a gain or loss in the income statement.
An affiliate in which the Company has a 50% ownership interest (Eaton Rapids Gas Storage System or “ERGSS”) used a floating-to-fixed interest rate swap agreement to hedge the variable interest rate payments on a portion of its long-term debt. This swap was designated as a cash flow hedge under SFAS 133, and the difference between the amounts paid and received under the swap was recorded as an adjustment to ERGSS’s interest expense
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7.
Risk Management Activities and Derivative Transactions (continued)
over the term of the agreement. In March 2006, the swap and related long-term debt matured and ERGSS repaid the debt. The Company’s share of changes in the fair value of the swap was recorded in accumulated other comprehensive income during the term of the swap.
The Company may, from time to time, enter into fixed-to-floating interest rate swaps in order to maintain its desired mix of fixed-rate and floating-rate debt. These swaps are designated as fair value hedges under SFAS 133, and the difference between the amounts paid and received under these swaps is recorded as an adjustment to interest expense over the term of the swap agreement. If the swaps are terminated, any unrealized gains or losses are recognized pro-rata over the remaining term of the hedged item as an increase or decrease in interest expense. The Company entered into one such interest rate swap in January 2004 in order to hedge one-third of its $150 million 7.125% notes due 2008. This agreement qualifies under the provisions of SFAS 133 as a fair value hedge. In accordance with SFAS 133, the Company’s Consolidated Statements of Financial Position at December 31, 2006, included a liability of $1.4 million and a decrease in long-term debt of $1.4 million related to this interest rate swap. At December 31, 2005, the Company’s Consolidated Statements of Financial Position included a liability of $1.7 million and a decrease in long-term debt of $1.7 million related to this interest rate swap.
The Company may also, from time to time, enter into floating-to-fixed interest rate swaps in order to maintain its desired mix of fixed-rate and floating-rate debt. These swaps are designated as cash flow hedges under SFAS 133, and the difference between the amounts paid and received under these swaps is recorded as an adjustment to interest expense over the term of the swap agreement. The Company entered into two such interest rate swaps each with a notional amount of $20 million, in November 2006. These swaps were entered into in order to hedge the LIBOR component of the interest payments for a one and two year period on a portion of the Company’s $55 million Bank Term Loan entered into on October 31, 2006. These swap agreements, which become effective February 27, 2007, qualify under the provisions of SFAS 133, as a cash flow hedge. For cash flow hedges, the effective portion of gains and losses on derivative transactions is reported as a component of other comprehensive income. Gains and losses related to hedge ineffectiveness for outstanding derivatives is computed on a quarterly basis and included in interest expense. During 2006, there was no significant amount of ineffectiveness reported in earnings. As of December 31, 2006, the Company’s Consolidated Statement of Financial Position included an asset of $0.1 million (representing the fair value of these swaps), with a like amount, net of income taxes, included in accumulated comprehensive income. For further information on the cash flow interest rate swaps entered into in November 2006 and the Company’s $55 million Bank Term Loan, refer to Note 4.
Note 8.
Pension Plans and Other Postretirement Benefits
Adoption of SFAS 158. The Company adopted SFAS 158 on December 31, 2006. SFAS 158 requires, among other things, that the Company recognize in its consolidated statements of financial position the funded status of its defined benefit pension and postretirement benefit plans measured as the difference between the fair value of plan assets and the related benefit obligation, with a corresponding adjustment to accumulated comprehensive income, net of tax. Upon the adoption of SFAS 158, the Company recorded an additional $21.9 million of net accrued/prepaid pension and other postretirement costs and a $0.4 million decrease in intangible assets, with a corresponding adjustment to accumulated comprehensive income, net of income taxes. As a result of adopting SFAS 158, the Company’s accumulated comprehensive income included $30.7 million (excluding the effects of income taxes), representing the unrecognized prior service costs and unrecognized gains and losses of the Company’s pension and postretirement plans. The Company determined that a major portion of this amount was recoverable in future periods under the regulatory rate-setting process, as provided for under the provisions of SFAS 71. As a result, $29.6 million of the unrecognized prior service costs and unrecognized gains and losses (less certain income tax benefits) were reclassified from accumulated comprehensive income to regulatory assets in December 2006. The remaining balance of $1.1 million represents the unrecognized prior service costs and unrecognized gains and losses of the Company’s supplemental executive retirement plan (“SERP”), which is discussed in this note under the section entitled “Pensions.” For additional information on SFAS 158 and its impact on the Company, refer to Note 1 under the
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 8.
Pension Plans and Other Postretirement Benefits (continued)
section entitled “New Accounting Standards.” For additional information on the regulatory assets impact of the reclassification, refer to Note 2.
The incremental effect of the adoption of SFAS 158 and the adjustment for regulatory treatment on the Consolidated Statement of Financial Position at December 31, 2006, for all of the Company’s pension and other postretirement plans is presented in the following table:
Pensions. The Company has defined benefit pension plans for eligible employees (“Pension Plans”). Benefits under the Pension Plans are generally based upon years of service or a combination of years of service and compensation during the final years of employment. The Company’s funding policy is to contribute amounts annually to fund the Pension Plans based upon actuarial and economic assumptions intended to achieve adequate funding of projected benefit obligations. The Company also has a SERP, which is an unfunded defined benefit pension plan.
The Company contributed $6.7 million to fund its Pension Plans during 2006. The Company estimates it will contribute $4.7 million to fund its Pension Plans in 2007.
Other Postretirement Benefits. The Company has postretirement benefit plans (“Postretirement Plans”) that provide certain medical and prescription drug benefits to eligible retired employees, their spouses and covered dependents. Determination of benefits is based on a combination of the retiree’s age and years of service at retirement. The Company accounts for retiree medical benefits in accordance with SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” This standard requires the full accrual of such costs during the years that the employee renders service to the Company until the date of full eligibility.
In each of 2006, 2005 and 2004, the Company expensed retiree medical costs of $1.3 million, $1.0 million and $1.2 million, respectively. The retiree medical expense for each of those years includes $0.9 million of amortization of previously deferred retiree medical costs. Prior to getting regulatory approval for the recovery of retiree medical benefits in rates, the Company deferred, as a regulatory asset, any portion of retiree medical expense that was not yet provided for in customer rates. After receiving rate approval for recovery of such costs, the Company began amortizing, as retiree medical expense, the amounts previously deferred. The Company, as a matter of practice, has paid retiree medical costs from its corporate assets. During 2006, the Company paid $1.3 million from its corporate assets, net of participant contributions, to cover retiree medical costs. The Company estimates it will pay $1.6 million from its corporate assets or its funded Postretirement Plans in 2007 to cover retiree medical costs.
The Company has certain Voluntary Employee Benefit Association (“VEBA”) trusts to fund its retiree medical benefits. There were no contributions to the VEBA trusts during 2006, 2005 and 2004. The Company can also partially fund retiree medical benefits on a discretionary basis through Internal Revenue Code Section 401(h) accounts. No cash contributions were made to the 401(h) accounts in 2006, 2005 and 2004.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 8.
Pension Plans and Other Postretirement Benefits (continued)
Net periodic pension and postretirement benefit costs for 2006, 2005 and 2004, included the following components:
The Company uses a measurement date of December 31 for all of its plans. The following tables provide the changes in the projected benefit obligations, plan assets and funded status of the Company’s Pension Plans and Postretirement Plans and other information as of December 31, 2006 and 2005:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(a)
This amount is reflected in regulatory assets, net of income tax benefits related to Medicare Part D subsidies.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 8.
Pension Plans and Other Postretirement Benefits (continued)
Assumptions. The following tables provide the assumptions used to determine the benefit obligations and the net periodic benefit costs for the Company’s pension plans and other postretirement benefit plans for 2006 and 2005:
The discount rate used by the Company is determined by reference to the CitiGroup pension discount curve, other long-term corporate bond measures and the expected cash flows of the plans. The duration of the securities underlying those indexes reasonably matches the expected timing of anticipated future benefit payments.
The expected long-term rate of return on plan assets is established based on the Company’s expectations of asset returns for the investment mix in its plans (with some reliance on historical asset returns for the plans). The expected returns of various asset categories are blended to derive an appropriate long-term assumption.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 8.
Pension Plans and Other Postretirement Benefits (continued)
Plan Assets. The weighted-average asset allocations of the Company’s Pension Plans and its Postretirement Plans at December 31, 2006, and 2005 are presented in the following table:
The Company has a target asset allocation of 70% equities and 30% debt instruments for funding its Pension Plans. This does not include certain insurance contracts for retirees. Year-end pension contributions and cash held for retiree pension payments also impact the actual allocation compared to the target allocation. The funding for the Postretirement Plans has a target allocation of 60% equities and 40% debt and other instruments.
The primary goal of the Company’s funding approach is to ensure that pension and other postretirement liabilities are met. An emphasis is placed on the long-term characteristics of individual asset classes and the benefits of diversification across multiple asset classes. The approach incorporates an assessment of the proper long-term level of risk for the plans, considering factors such as the long-term nature of the plans’ liabilities, the current funded status of the plans, and the impact of asset allocation on the volatility and magnitude of the plans’ contributions and expense.
Estimated Future Benefit Payments. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
401(k) Plans and Profit-Sharing Plans. The Company has defined contribution plans, commonly referred to as 401(k) plans, covering eligible employees. Certain of the 401(k) plans contain provisions for Company matching contributions. The amount expensed for the Company match provisions was $1.3 million for 2006, $1.2 million for 2005 and $1.1 million for 2004.
The Company has profit-sharing plans covering certain employees. Annual contributions are generally discretionary or determined by a formula, which contains minimum contribution requirements. Profit-sharing expense was $0.2 million for 2006, 2005 and 2004.
Note 9.
Share-Based Compensation
The Company’s 2004 Stock Award and Incentive Plan (“2004 Plan”), provides for the issuance, in various forms, of up to 1,500,000 shares of Common Stock, plus any shares that become available through forfeiture or
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9.
Share-Based Compensation (continued)
other prescribed means from the Company’s previous long-term incentive or stock option plans after the effective date of the 2004 Plan. Awards may be in the form of stock options, stock appreciation rights, restricted stock, deferred stock, bonus stock and awards in lieu of obligations, dividend equivalents, other share-based awards, or performance awards. Awards granted thus far under the 2004 Plan have been in the form of (i) stock options, (ii) performance share units and restricted stock units, and (iii) restricted stock. These awards are discussed below.
The Company also has a deferred compensation plan for its Board and an employee stock gift program. The deferred compensation plan allows for the deferral of Director compensation, at the Director’s election, and deferred amounts can be invested in a hypothetical fund that tracks the price changes of the Company’s Common Stock. Any deferral of Director compensation is expensed in the Company’s Consolidated Statement of Operations when earned by the Director. The employee stock gift program provides one free share of Company Common Stock to an employee the first time he or she enrolls in the Company’s program to make contributions to the Company’s DRIP via employee payroll deductions. The Board has decided to terminate the employee stock gift program, subject to satisfying any bargaining duty it may have with respect to such termination with the collective bargaining representatives of certain employee groups.
At December 31, 2006, there were approximately 581,000 share-based awards available to be granted to employees and Directors under these plans. There were no modifications to awards outstanding under these plans during the years ended December 31, 2006, 2005 and 2004. The Company recognized expense related to its share-based compensation arrangements of $1.8 million, $0.8 million and $0.2 million during 2006, 2005 and 2004, respectively. The tax benefit recognized in income in relation to this compensation expense was $0.7 million, $0.3 million and less than $0.1 million, during 2006, 2005 and 2004, respectively. The Company did not capitalize any expense related to its share-based arrangements during 2006, 2005 and 2004. The Company has issued, and expects to continue to issue, new shares of Common Stock upon the exercise of stock options or upon the settlement of performance share units and restricted stock units.
Restricted Stock Units for Executives. During 2004 and 2005, the Company issued 114,728 restricted stock units (“RSUs”) to certain Company executives under the 2004 Plan. Each RSU is equivalent to one share of Company Common Stock. 10,000 of the RSUs issued in 2004 have been forfeited because the executive to whom the RSUs were issued is no longer employed by the Company. Of the RSUs issued in 2005, 14,728 vest in full on the three-year anniversary of issuance as long as the executive who received the RSUs remains employed on the vesting date. The remaining 90,000 outstanding RSUs vest at different dates over the period from issuance to March 31, 2007. Approximately 42% of these remaining 90,000 RSUs vested in full on approximately the one-year anniversary of issuance, with the fulfillment of the requirement that the executives who received the RSUs remained employed on the vesting date. Approximately 29% of these remaining 90,000 RSUs vested in 2006, with the fulfillment of the requirements that the executives who received the RSU’s remained employed on the vesting date and that certain performance goals be attained. The remaining 29% vest in 2007, subject to the attainment of certain performance targets and as long as the executives remain employed on the vesting dates. Notwithstanding these vesting conditions, the RSUs vest in their entirety upon consummation of a change in control of the Company, as defined in the Company’s severance agreements with its executives. Settlement of the vested RSUs will be made in shares of the Company’s Common Stock. The earliest any such settlements would occur is 2007.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9.
Share-Based Compensation (continued)
A summary of information about non-vested RSUs as of December 31, 2006, and changes during the year then ended is presented below:
The grant date fair value of an RSU is equal to the price of the underlying share of the Company’s Common Stock on the grant date. During 2004, 97,500 RSUs were granted to executives with a weighted average grant date fair value of $5.70 per unit. During 2005, 17,228 RSUs were granted to executives with a weighted average grant date fair value of $6.66 per unit. No RSUs were granted to executives during 2006. During 2005, and 2006, 35,000 RSUs with a total fair value of $0.2 million and 28,750 RSUs with a total fair value of $0.2 million, respectively, were earned and vested but, under the terms of the RSUs, will not be paid out in shares of Common Stock until 2007. As of December 31, 2006, there was a total of 63,750 RSUs earned and vested. As of December 31, 2006, there was $0.1 million of total unrecognized compensation cost related to non-vested RSUs granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.1 years.
Employee Performance Share Units. The Company also grants performance share units (“PSUs”) to certain of its employees under the 2004 Plan. The Company grants a specific number of PSUs, which is referred to as the “Target Grant.” During 2006 and 2005, the Company granted 225,705 and 168,667 PSUs, respectively. Each PSU is equivalent to one share of Company Common Stock. Under the terms of the PSUs, the grantee can vest in PSUs equivalent to 25% to 150% of the Target Grant, if actual performance results are within 25% to 150% of the target performance goals. Following a three-year performance period (or a two-year vesting period for 25,000 of the PSUs issued in 2005), a percentage of PSUs will vest if the individuals who received the PSUs are actively employed with the Company on the last day of the performance period and if the threshold level of performance is met or exceeded with respect to at least one of the established performance goals. On February 22, 2007, the Board approved an amendment to the form PSU award agreement, to effect the immediate satisfaction of all performance criteria and the immediate award of all PSUs at 100% of the Target Grant upon the effective date of a change in control of the Company, irrespective of the grantee’s employment status after or as a result of the change in control of the Company. Additionally, all PSUs granted by the Company after February 22, 2007, will be granted pursuant to a form PSU award agreement that provides for vesting in the same manner. Settlement of vested PSUs will be made in shares of the Company’s Common Stock.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9.
Share-Based Compensation (continued)
A summary of information about non-vested PSUs as of December 31, 2006, and changes during the year then ended is presented below:
The grant date fair value of a PSU is equal to the price of the underlying share of the Company’s Common Stock on the grant date. The weighted-average grant date fair value of PSUs granted was $5.39 per unit during 2006, and $6.15 per unit during 2005. There were no PSUs settled in shares of Common Stock during 2006, and 2005. As of December 31, 2006, there was $1.1 million of total unrecognized compensation cost related to non-vested PSUs granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.7 years.
Restricted Stock for Directors. The Company grants shares of restricted Common Stock to non-employee Directors under the 2004 Plan as part of the compensation paid to Directors. The restricted Common Stock vests over a three-year period as long as the individuals who received the restricted Common Stock continue to serve on the Board on the vesting dates. Notwithstanding these vesting conditions, the restricted Common Stock for Directors vests in its entirety upon consummation of a change in control of the Company, as defined in the 2004 Plan, and in certain other circumstances.
A summary of information about non-vested restricted Common Stock as of December 31, 2006, and changes during the year then ended is presented below:
The grant date fair value of a share of restricted Common Stock is equal to the price of a share of the Company’s Common Stock on the grant date. During 2006 and 2005, 9,750 shares and 168,750 shares, respectively, of restricted Common Stock were granted with a weighted average grant date fair value of $5.45 per share and $5.83 per share, respectively. During 2006 and 2005, 65,250 shares and 7,250 shares, respectively, of restricted Common Stock were vested. The total value of shares vested during 2006 and 2005, were $0.4 million and less than $0.1 million, respectively. As of December 31, 2006, there was $0.4 million of total unrecognized compensation cost related to non-vested restricted Common Stock granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.2 years.
Options to Purchase Common Stock. The exercise price of all stock options granted under the 2004 Plan is equal to the average of the high and low market price of the Company’s Common Stock on the option grant date. The options vest over the three-year period following the date of grant and expire ten years from the date of grant.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9.
Share-Based Compensation (continued)
Notwithstanding this three-year vesting condition, stock options vest in their entirety upon consummation of a change in control of the Company, as defined in the Company’s severance agreements with its executives and the 2004 Plan. Both the number of options granted and the exercise price are adjusted for any stock dividends and stock splits occurring during the life of the options. The fair values of the options were estimated at the grant date using a Black-Scholes option pricing model and the weighted average assumptions shown in the table below:
The expected volatility is based on the historical volatility of the Company’s Common Stock. The Company uses historical data and other factors to estimate option exercise and employee termination within the model. The expected term of options granted is derived from historical data and other factors and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of an option is based on the U.S. Treasury yield curve in effect at the date of grant.
A summary of information about options as of December 31, 2006, and changes during the year then ended is presented below:
The weighted-average grant date fair value of options granted during 2006 2005 and 2004 was $2.11, $2.59 and $2.20, respectively. During 2006 and 2005, the total intrinsic value of options exercised and the total cash received and tax benefits realized from the exercise of options were less than $0.1 million, combined. As of December 31, 2006, there was $0.6 million of total unrecognized compensation cost related to non-vested stock options granted under the 2004 Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years.
For further information regarding the impact of the adoption of SFAS 123-R on share-based compensation, refer to the caption “Share-Based Compensation” in Note 1.
Note 10.
Earnings Per Share
The Company computes earnings per share (“EPS”) in accordance with SFAS 128, “Earnings per Share.” SFAS 128 requires the computation and presentation of two EPS amounts, basic and diluted. Basic EPS is computed by dividing income available to holders of the Company’s Common Stock by the weighted average number of shares of Common Stock outstanding during the period. The computation of diluted EPS is similar to the computation of basic EPS, except that the weighted average number of shares of Common Stock outstanding
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 10.
Earnings Per Share (continued)
is increased to include any additional shares that would be issued if stock options were exercised, shares of Preferred Stock and Convertible Preference Stock (“CPS”) were converted to shares of Common Stock, shares of non-vested restricted stock were fully vested, and RSUs and PSUs were settled in shares of Common Stock. However, the diluted EPS calculation does not include these potential shares in instances when their inclusion in the diluted EPS calculation results in an EPS figure that is anti-dilutive when compared to basic EPS.
The following table indicates the potential dilutive impact of the Company’s dilutive securities on average Common Stock shares outstanding and potential adjustments to the Company’s Consolidated Statements of Operations when computing diluted EPS:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 10.
Earnings Per Share (continued)
The following table outlines the computations of basic and diluted EPS. The potential adjustments indicated in the previous table are not included in the following computations of diluted EPS if their impact for a given period is anti-dilutive when compared to basic EPS for the period:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 11.
Business Segments
The Company follows SFAS 131,“Disclosure about Segments of an Enterprise and Related Information,” which specifies standards for reporting information about operating segments (“business segments”) in annual financial statements and requires selected information in interim financial statements. Business segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision-making group, to make decisions on how to allocate resources and to assess performance. The Company’s chief operating decision-making group is the Chief Executive Officer (“CEO”) and certain other executive officers who report directly to the CEO. The Company evaluates the performance of its business segments based on the operating income generated. Operating income does not include income taxes, interest expense, discontinued operations, and non-operating income and expense items.
The Company has one reportable business segment known as the Gas Distribution Business. Under SFAS 131, a business segment that does not exceed certain quantitative levels is not considered a reportable business segment. Instead, business segments that do not exceed the quantitative thresholds are combined and reported in a separate category with other business activities that do not meet the definition of a business segment. The Company refers to this other category as “Corporate and Other.” For a description of the Company’s Gas Distribution business segment, and a description of the Company’s non-separately reportable business segments included in Corporate and Other, refer to Note 1. The accounting policies of the Company’s business segments are the same as those described in Note 1 except that intercompany transactions have not been eliminated in determining individual segment results.
The Company’s corporate division is a cost center rather than a business segment. Any corporate operating expenses that do not relate to the ongoing operations of the Company’s business segments or are not allocable to them under various regulatory rules are not allocated to those segments. Instead, these unallocated expenses remain on the books of the corporate division. The corporate division is included in Corporate and Other.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 11.
Business Segments (continued)
The following table provides business segment information as well as a reconciliation of the segment information to the applicable line in the Consolidated Financial Statements:
(a)
Includes the elimination of intercompany gas distribution revenue of $221, $209 and $199 for 2006, 2005 and 2004. Includes the elimination of intercompany corporate and other revenue of $7,943, $7,383 and $6,866 for 2006, 2005 and 2004, respectively.
(b)
Gas Distribution capital investments for 2005 include $3,076 for a business acquisition.
(c)
Effective January 1, 2004, the Company began accounting for the construction services segment as a discontinued operation. Accordingly, its operating results are segregated and reported as discontinued operations in the Consolidated Statements of Operations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 12.
Investments in Affiliates
The equity method of accounting is used for interests where the Company has significant influence, but does not control an entity. The Company has a 50% ownership interest in ERGSS that it accounts for using the equity method of accounting. The investment in ERGSS is reported in deferred charges and other assets in the Consolidated Statements of Financial Position. ERGSS provides natural gas storage services to the Company’s Gas Distribution Business and SEMCO Energy Ventures, Inc. (“Ventures”), a non-regulated subsidiary of the Company. ERGSS had annual operating revenues associated with services provided to the Gas Distribution Business of $3.1 million, $3.2 million and $3.4 million in 2006, 2005 and 2004, respectively. ERGSS had operating revenues associated with providing services to Ventures of $0.1 million in 2006. The table below summarizes the financial information for ERGSS:
The Company’s previously had common equity investments of $1.2 million in two capital trust subsidiaries. In 2005, these investments were redeemed by the trusts. Refer to Note 4 for further information.
Note 13.
Commitments and Contingencies
Capital Investments. The Company’s plans for expansion and improvement of its business properties are continually reviewed. Aggregate capital expenditures for property in 2007 are projected to be approximately $39.7 million.
Lease Commitments. The Company leases buildings, vehicles and equipment. The resulting leases are classified as operating leases in accordance with SFAS 13, “Accounting for Leases.” A significant portion of the Company’s vehicles are leased. Leases on the majority of the Company’s new vehicles are for a minimum of twelve months. The Company has the right to extend each vehicle lease annually and to cancel the extended lease at any time. During 2002, the Company sold two of its buildings located in Port Huron, Michigan to Acheson Ventures LLC (“Acheson”) and leased these facilities back over the period January 2003 through January 2005. The annual lease payments associated with these facilities amounted to approximately $0.5 million. In February 2005, the Company began leasing its new Port Huron headquarters building from Acheson for annual lease payments of $0.8 million.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 13.
Commitments and Contingencies (continued)
The Company’s future minimum lease payments that have initial or remaining noncancelable lease terms in excess of one year at December 31, 2006, totaled $16.9 million consisting of (in millions):
Total lease payments were approximately $3.1 million, $2.9 million and $3.1 million in 2006, 2005 and 2004, respectively. The annual future minimum lease payments are less than the lease payments incurred in 2004 through 2006, because most of the vehicle leases at December 31, 2006, were on a month-to-month basis and were subject to cancellation at any time. However, management expects to renew or replace substantially all of these leases.
Sublease Commitments. In March 2006 the Company entered into a sublease with a subtenant whose payments are covering a portion of the Company’s remaining lease obligations on the Farmington Hills, Michigan, office space that was the Company’s former headquarters. The tenant’s obligation to make these sublease payments extends through March 31, 2011. As of December 31, 2006, the future payments that the subtenant is obligated to pay amounted to approximately $1.0 million.
Also, in February 2005, in conjunction with the commencement of the Company’s lease of its new Port Huron headquarters building from Acheson, Acheson agreed to make the lease payments on the Farmington Hills, Michigan, office space that was the Company’s former headquarters. Acheson’s obligation to make these lease payments extends through March 31, 2011, when the Company’s lease on the Farmington Hills office space expires. Acheson ceased payments on these lease obligations in June 2005. Acheson’s obligation to make these payments is in dispute. For additional information on Acheson’s obligation and related legal action, refer to the caption “Other Contingencies” within this Note 13.
Commitments for Natural Gas Supplies. The Company enters into contracts to purchase natural gas and natural gas transportation and storage services from various suppliers for its Gas Distribution Business. These contracts, which have expiration dates that range from 2007 to 2015, are used to assure an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. The Company’s gas purchase contractual obligations as of December 31, 2006, total $288.5 million, consisting of (in millions):
Guarantees. The Company has issued letters of credit through financial institutions for the benefit of third parties that have extended credit or have financial exposure to the Company. At December 31, 2006, the outstanding letters of credit amounted to $7.7 million. Under the terms of these letters of credit, if the Company does not pay amounts when due under the covered contracts, the beneficiary may present its claim for payment to the financial institution, which will in return request payment from the Company. The letters of credit are entered into on a short term basis, normally every six-to-twelve months, and are then renewed for another short term period. At December 31, 2006, the scheduled expiration dates for these letters of credits ranged from February 2007 through September 2007.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 13.
Commitments and Contingencies (continued)
Environmental Issues. Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. Residual byproducts of these processes may have caused environmental conditions that require investigation and remediation. The Company owns seven sites in Michigan where such manufactured gas plants were located. Even though the Company never operated manufactured gas facilities at four of the sites, and did so at one site for only a brief period of time, the Company is subject to local, state and federal laws and regulations that require, among other things, the investigation and, if necessary, the remediation of contamination associated with these sites, irrespective of fault, legality of initial activity, or ownership, and which may impose liability for damage to natural resources. The Company has complied with the applicable Michigan Department of Environmental Quality (“MDEQ”) requirements, which require current landowners to mitigate unacceptable risks to human health from the byproducts of manufactured gas plant operations and to notify the MDEQ and adjacent property owners of potential contaminant migration. The Company is currently investigating these sites and anticipates conducting any necessary additional investigatory and remediation activities as appropriate. The Company has already remediated and closed a site related to one of the manufactured gas plant sites, with the MDEQ’s approval.
The Company is also attempting to identify other potentially responsible parties to bear some or all of the costs and liabilities associated with the investigatory and remediation activities at several of these sites and also is pursuing recovery of the costs of these activities from insurance carriers. The Company is unable to predict, however, whether and to what extent it will be successful in involving other potentially responsible parties in investigatory or remediation activities, or in bearing some or all of the costs thereof, or in securing insurance recoveries for some or all of the costs associated with these sites.
The Company accrues for costs associated with environmental investigation and remediation obligations when such costs are probable and reasonably estimable. Accruals for estimated costs for environmental remediation obligations are generally recognized no later than the completion of the Company’s Remedial Action Plan (“RAP”) for a site. Such accruals are expected to be adjusted as further information becomes available or circumstances change. At three of the Company’s sites, the Company has begun efforts to determine the extent of remediation, if any, that must be performed, with the expectation of completing and submitting a RAP for each of the sites to the MDEQ. As a result of investigational work performed to date, the Company’s Consolidated Statements of Financial Position include an accrual and a corresponding regulatory asset in the amount of $1.6 million at December 31, 2006, for estimated environmental investigation and remediation costs that it believes are probable at these three sites. The Company has not discounted this accrual to its present value. The accrued costs are expected to be paid out over the next three years.
The accrual of $1.6 million represents what the Company believes is probable and reasonably estimable. However, the Company also believes that it is reasonably possible that there could be up to an estimated $18.5 million of environmental investigation and remediation costs for these three sites, in addition to the $1.6 million already accrued. It is also reasonably possible that the amount accrued or the reasonably possible range of costs may change in the future as the Company’s investigation of these sites continues and any remediation activities are undertaken. The Company’s cost estimates have been developed using probabilistic modeling, advice from outside consultants, and judgment by management. The liabilities estimated by the Company are based on a current understanding of the costs of investigation and remediation. Actual costs, which may differ materially from these estimates, may vary depending, among other factors, on the environmental conditions at each site, the level of any remediation required, and changes in applicable environmental laws.
The Company has done less investigational and remediation work at the remaining four sites but has met all applicable MDEQ requirements. The Company believes that further investigation and any remediation of environmental conditions at these sites may be the obligation of other potentially responsible parties. It is reasonably possible that the Company’s current estimate concerning costs likely to be incurred in connection with the investigation and any remediation of conditions at these four sites may change in the future as new information becomes available and circumstances change, including the Company’s further evaluation of the obligations of
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 13.
Commitments and Contingencies (continued)
other potentially responsible parties for these costs. If this were to occur, the Company’s liability with respect to costs at these four sites could be material.
In accordance with an MPSC accounting order, the payment by the Company of environmental assessment and remediation costs associated with certain manufactured gas plant sites and other environmental expenses are deferred and amortized over ten years. Rate recognition of the related amortization expense does not begin until the costs are subject to review in a base rate case.
Personal Property Taxes. The Company and other Michigan utilities have asserted that Michigan’s valuation tables in effect prior to 2000 resulted in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (“STC”) are used to estimate the reduction in value of personal property based on the property’s age. In 1998, the Company began filing its personal property tax information with local taxing jurisdictions using a revised calculation of the value of personal property subject to taxation. A number of local taxing jurisdictions accepted the revised calculation, and the Company recorded lower property tax expense in 1998 and subsequent years associated with these taxing jurisdictions. The Company has also filed appeals to recover excess payments made in 1997 and subsequent years based on the revised calculation and recorded lower property tax expense as a result of the filings.
In November 1999, the STC approved new valuation tables for utility personal property. The new tables became effective in 2000 and are being used for current year assessments in most jurisdictions. However, several local taxing jurisdictions took legal actions attempting to prevent the STC from implementing the new valuation tables and others continued to prepare assessments based on the superseded tables. The legality of the new valuation tables providing lower values for gas distribution property was resolved in favor of the STC in January 2004.
Throughout the period that property tax appeals for prior years have been pending, the Company has reflected the amount of the excess property tax payments that it expected to recover in prepaid expenses in its Consolidated Statements of Financial Position. During 2004, the Company reduced its estimate for recovery of certain of these prior years excess property tax payments by $1.4 million, such that at December 31, 2004, the Company had approximately $2.5 million recorded in prepaid expenses for its estimated recovery. During 2005, the Company made settlement offers to all taxing jurisdictions involved with the property tax appeals. Numerous taxing jurisdictions have accepted the Company’s settlement offers and the Company has reduced its property tax expense for the amount of property tax settlements above the $2.5 million recovery estimated by the Company at December 31, 2004. In 2006 and 2005, the reductions in property tax expense associated with these settlements were approximately $1.5 million and $0.5 million, respectively. The Company will continue to seek settlements with taxing jurisdictions that have not yet accepted the Company’s offers. If the taxing jurisdictions that have not yet accepted the Company’s settlement offers were to accept the Company’s offers, it would result in additional property tax refunds of approximately $0.4 million. If any taxing jurisdictions do not accept the Company’s settlement offers, the property tax appeals involving these jurisdictions would move forward before the Michigan Tax Tribunal.
Other Contingencies. In the normal course of business, the Company may be a party to lawsuits and administrative proceedings before various courts and government agencies. The Company also may be involved in private dispute resolution proceedings. These lawsuits and proceedings may involve personal injury, property damage, contractual issues and other matters (including alleged violations of federal, state and local laws, rules, regulations and orders). Management cannot predict the outcome or timing of any pending or threatened litigation or of actual or possible claims. Except as otherwise stated, management believes resulting liabilities, if any, will not have a material adverse impact upon the Company’s financial position, results of operations, or cash flows.
In September 2002, the Company agreed to relocate its headquarters to Port Huron, Michigan, and leased part of a new office building in Port Huron from Acheson. As part of the transaction, Acheson agreed to sublease office space occupied by the Company in Farmington Hills, Michigan, and, beginning in February 2005, began to pay the Company’s Farmington Hills lease costs (approximately $36,000/month until March 31, 2011, when the
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 13.
Commitments and Contingencies (continued)
Farmington Hills lease expires), as agreed. In June 2005, Acheson ceased making these payments, ostensibly because the Company had allegedly breached its obligations by maintaining a satellite office in Troy, Michigan, for certain executives who also have offices in the Company’s Port Huron headquarters. The Company has filed an action in Michigan state court, seeking (i) damages for Acheson’s failure to pay the Company’s Farmington Hills lease costs, and (ii) a declaratory judgment that the Company has met its obligations to Acheson. On January 16, 2006, Acheson answered the Company’s complaint, filed counter-claims alleging breach of contract, fraud, and negligent misrepresentation, and sought a change of venue for these proceedings, to Port Huron, Michigan. The Company made filings to answer Acheson’s counter claims, denying any liability to Acheson and opposing a change of venue. The court subsequently ruled that venue for this case was properly laid in Oakland County, Michigan. Pre-trial activities in this case, including Acheson’s motion renewing its venue change request, are underway. The court ruled on February 21, 2007, that the venue was proper in Port Huron, Michigan, essentially overturning its earlier venue ruling. The Company expects to ask the court to reconsider this recent venue ruling.
To mitigate its damages, the Company paid the Farmington Hills lease costs and marketed the space to prospective subtenants, since the time Acheson ceased making the lease payments. In March 2006, the Company entered into a sublease with a subtenant that will pay a portion of these lease costs. As a result of this sublease agreement, the Company recorded a $1.2 million pre-tax loss in the first quarter of 2006 representing the difference between the present value of the amount it expects to receive from the subtenant and the present value of the remaining amount owed to the landlord under the terms of the lease.
Aurora Gas gave the Company notice of the suspension of gas deliveries, and subsequently suspended deliveries, to the Company’s Alaska Pipeline Company subsidiary (which, in turn, are delivered to the Company’s ENSTAR Division for resale to its customers in Alaska) under the gas supply contract between the Company and Aurora Gas pursuant to which Aurora Gas sells natural gas to the Company from the Moquawkie natural gas field (the “Moquawkie Contract”). Aurora Gas asserted that it was permitted to take these actions because production has become “Not Economic,” as that term is defined in the Moquawkie Contract. The Company disagrees with Aurora Gas’s contentions, and attempts to resolve this matter informally were unsuccessful. The Company filed suit against Aurora Gas and an affiliate in Alaska state court asserting, among other things, a breach of contract claim. Aurora Gas has defended against the Company’s claims in this lawsuit by insisting upon its right to suspend gas deliveries. For further information concerning this dispute with Aurora Gas and related rate recovery implications, refer to Note 2 - Regulatory Matters.
Note 14.
Acquisitions, Disposals and Discontinuation of Operations
Acquisition of Peninsular Gas Company. On June 1, 2005, the Company acquired substantially all of the assets and certain liabilities of Peninsular Gas for $3.0 million in cash. The assets acquired included approximately $0.3 million in cash. In accordance with the asset purchase agreement, the Company paid an additional $0.3 million to the seller for excess working capital acquired. The cash paid by the Company to acquire Peninsular Gas, including $0.1 million of transaction costs and the excess working capital payment, amounted to $3.1 million, net of the cash acquired. This acquisition added approximately 4,000 customers to the Company’s Gas Distribution Business in the upper peninsula of Michigan. The operating results of Peninsular Gas for all of 2006 and part of 2005 (the period June 1 through December 31, 2005), are reflected in the Company’s Consolidated Statements of Operations. The assets and liabilities of Peninsular Gas are reflected in the Company’s Consolidated Statements of Financial Position at December 31, 2005 and 2006.
Disposal of Construction Services Business Segment. The Company began marketing the construction services business for sale during the first quarter of 2004. As a result, the Company has accounted for the business as a discontinued operation and, accordingly, the operating results and the estimated loss on the disposal of this business are segregated and reported as discontinued operations in the Consolidated Statements of Operations. In September 2004, the Company sold the assets of its construction services business to InfraSource Services, Inc. for approximately $21.3 million. The proceeds from the sale were used for capital expenditures and general corporate purposes.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 14.
Acquisitions, Disposals and Discontinuation of Operations (continued)
Operating income (losses), net of income taxes, from the discontinued operations were $0.5 million and $(4.6) million, respectively, for 2005 and 2004. The Company’s income from discontinued operations for 2005 was from a settlement of litigation. Also included in discontinued operations for 2004 is a loss of $4.7 million, net of income taxes, which the Company incurred on the disposal of the discontinued segment.
Components of amounts reflected in the Consolidated Statements of Operations for the construction services business are presented in the following table:
Consolidated Statements of Operations Data
Note 15.
Subsequent Event
On February 22, 2007, the Company entered into an Agreement and Plan of Share Exchange (the “Exchange Agreement”) by and among the Company, Cap Rock Holding Corporation (“Cap Rock”) and Semco Holding Corporation, a direct wholly-owned subsidiary of Cap Rock (“Parent”), under which Parent will acquire all the outstanding Common Stock and Preferred Stock of the Company. Pursuant to the terms of the Exchange Agreement, each issued and outstanding share of Common Stock and Preferred Stock of the Company will be transferred to Parent. The Common Stock will be transferred for the right to receive $8.15 in cash per share, without interest, and the Preferred Stock will be transferred for the right to receive approximately $213.07 in cash per share plus a make-whole premium to be calculated at closing, without interest (collectively, the “Exchange Consideration”), in each case on the terms and subject to the conditions set forth in the Exchange Agreement (collectively, the “Share Exchange”). The Board, upon the unanimous recommendation of its Finance Committee (which is comprised entirely of independent directors), approved the Exchange Agreement and has recommended that the holders of the Company’s Common Stock approve the Share Exchange at a special meeting to be held at a future date determined in accordance with the Exchange Agreement.
The Company has made customary representations, warranties and covenants in the Exchange Agreement. The Exchange Agreement contains a “go shop” provision pursuant to which the Company has the right to solicit and engage in discussions and negotiations with respect to competing acquisition proposals for 35 days following the date of the Exchange Agreement. In accordance with the Exchange Agreement, the Board, through its Finance Committee and with the assistance of the Company’s advisors, intends to solicit superior proposals during this period. There can be no assurance that the solicitation of superior proposals will result in an alternative transaction.
Following the “go shop” period, as it may be extended, the Company is subject to a “no shop” restriction on its ability to solicit third-party proposals, provide information and engage in discussions and negotiations with third parties. The no shop provision is subject to a “fiduciary out” provision that allows the Company to provide information and participate in discussions and negotiations with respect to third-party acquisition proposals submitted after the “go shop” period that the Board believes in good faith, after consultation with its financial
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 15.
Subsequent Event (continued)
advisors and outside counsel, constitute or could reasonably be expected to result in a “superior proposal,” as defined in the Exchange Agreement.
The Company may terminate the Exchange Agreement under certain circumstances, including if its Board determines in good faith that it has received a “superior proposal” and that failure to terminate the Exchange Agreement would be inconsistent with its fiduciary duties, and the termination otherwise complies with certain terms of the Exchange Agreement. In connection with such termination, the Company must pay a termination fee to Parent and reimburse Parent for its out-of-pocket expenses, subject to a cap. The amount of such termination fee and expense reimbursement will depend on whether such termination is in connection with a “superior proposal” submitted during or after the “go-shop” period.
Consummation of the transaction is not subject to a financing condition, but is subject to various other conditions, including approval of the Share Exchange by the holders of the Company’s Common Stock, approval by the RCA, expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and satisfaction of other customary closing conditions.
Note 16.
Quarterly Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Earnings per share for each quarter is calculated based upon the weighted average number of shares outstanding during each quarter. As a result, adding the earnings per share for each quarter of a year may not equal annual earnings per share due to changes in shares outstanding throughout the year. Due to the seasonal nature of the Company’s Gas Distribution Business, the results of operations reported on a quarterly basis show substantial variations.
SCHEDULE II CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Disclosure Controls and Procedures. As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the CEO and the CFO have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2006, to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the CEO and CFO, to allow timely decisions regarding required disclosure. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that the Company’s disclosure controls and procedures will detect or uncover every situation involving the failure of persons within the Company to disclose material information otherwise required to be set forth in the Company’s periodic reports.
Management’s Report on Internal Control Over Financial Reporting. 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)). The Company’s internal control over financial reporting is a process designed under the supervision the Company’s CEO and CFO to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. The 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 Company’s assets; (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 the Company’s receipts and expenditures are being made only in accordance with authorizations of management and the Company’s Board; 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.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management concluded that, as of December 31, 2006, the Company’s internal control over financial reporting was effective.
Management’s assessment of the effectiveness of the Company’s 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 its report contained in Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting. During the fourth quarter of the year ended December 31, 2006, the Company put into service a new Customer Information System for use in its Michigan operations. The Customer Information System is the primary computer program used to, among other things, bill customers for gas service. Certain internal controls were changed as a result of implementing this new system. The Company tested those controls prior to and after implementing the new system and believes that the changes in internal controls have not materially affected, nor are they reasonably likely to materially affect, the Company’s internal control of financial reporting. Other than the implementation of the new Customer Information System, no other change in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f)
and 15d-15(f) of the Securities and Exchange Act of 1934) occurred during the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B.
Other Information
Not applicable.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
The information appearing under the captions “Information About Nominees, Directors and Executive Officers,” the subheading “Audit Committee” under the caption “Committees of the Board of Directors and Meeting Attendance” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2007 Annual Meeting of Common Shareholders is incorporated by reference herein. In February 2003, the Company’s Board adopted a Code of Business Conduct and Ethics (“Code of Ethics”) that applies to all of the Company’s employees (including the Company’s officers), Directors, affiliates, agents, consultants, advisors and representatives. The Company had a Code of Ethics in place prior to February 2003, but expanded the information provided into a handbook on conduct and ethics that would be better understood by those required to abide by it. The Company’s Code of Ethics was filed as Exhibit No. 99.2 to the Form 10-K for the year ended December 31, 2003, and can also be found on the Company’s website at www.semcoenergy.com in the Investor Information section under Corporate Governance.
Item 11.
Item 11.
Executive Compensation
The information appearing under the captions “Executive Compensation” (including the subheadings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table for 2006,” “Grants of Plan-Based Awards for 2006,” “Outstanding Equity Awards at 2006 Fiscal Year-End,” “Option Exercises and Stock Vested in 2006,” “Pension Benefits,” “Estimated Pension Benefits Table at December 31, 2006,” and “Potential Payments Upon Termination or Change-in-Control”) and “Compensation of Directors” (including the subheadings “Director Compensation”, “Cash Compensation”, “Equity Compensation”, and “Deferred Compensation”) in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2007 Annual Meeting of Common Shareholders is incorporated by reference herein. There are no compensation committee interlocks or insider participation.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information appearing under the caption “Beneficial Ownership” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2007 Annual Meeting of Common Shareholders is incorporated by reference herein. Information regarding the Company’s equity compensation plans, including plans approved by security holders and plans not approved by security holders, appearing under the caption “Equity Compensation Plan Information” in the Company’s definitive Proxy Statement (to filed pursuant to Regulation 14A) with respect to the Company’s 2007 Annual Meeting of Common Shareholders is incorporated by reference herein.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information appearing under the caption “Certain Relationships and Related Transactions” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2007 Annual Meeting of Common Shareholders is incorporated by reference herein.
Item 14.
Item 14.
Principal Accountant Fees and Services
The information appearing under the caption “Principal Accountant Fees” in the Company’s definitive Proxy Statement (to be filed pursuant to Regulation 14A) with respect to the Company’s 2007 Annual Meeting of Common Shareholders is incorporated by reference herein.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules
EXHIBITS, INCLUDING THOSE INCORPORATED BY REFERENCE
*
Indicates management contract or compensatory plan or arrangement.
Key to Exhibits Incorporated by Reference
(a)
Filed with SEMCO Energy, Inc.’s 1997 Proxy Statement, filed March 6, 1997, File No. 0-8503.
(b)
Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 1996, filed March 31, 1997, File No. 0-8503.
(c)
Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended September 30, 2000, filed November 13, 2000, File No. 001-15565.
(d)
Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2000, filed March 30, 2001, File No. 001-15565.
(e)
Filed with SEMCO Energy, Inc.’s Form 8-K filed June 21, 2001, File No. 001-15565.
(f)
Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended September 30, 2001, filed November 13, 2001, File No. 001-15565.
(g)
Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2001, filed March 27, 2002, File No. 001-15565.
(h)
Filed with SEMCO Energy, Inc.’s Form 8-K filed September 20, 2002, File No. 001-15565.
(i)
Filed with SEMCO Energy, Inc.’s Registration Statement, Form S-4, No. 333-107200, filed July 21, 2003.
(j)
Filed as Appendix A to SEMCO Energy, Inc.’s 2004 Proxy Statement, filed April 6, 2004, pursuant to Rule 14a-6 of the Exchange Act, File No. 001-15565.
(k)
Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2003, filed March 4, 2004, File No. 001-15565.
(l)
Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended March 31, 2004, filed May 7, 2004, File No. 001-15565.
(m)
Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2004, filed March 8, 2005, File No. 001-15565.
(n)
Filed with SEMCO Energy, Inc.’s Form 8-K filed March 17, 2005, File No. 001-15565.
(o)
Filed with SEMCO Energy, Inc.’s Registration Statement, Form S-3, No. 333-124005, filed April 11, 2005.
(p)
Filed with SEMCO Energy, Inc.’s Form 8-K filed July 1, 2005, File No. 001-15565.
(q)
Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended June 30, 2005, filed August 3, 2005, File No. 001-15565.
(r)
Filed with SEMCO Energy, Inc.’s Form 8-K filed September 19, 2005, File No. 001-15565.
(s)
Filed with SEMCO Energy, Inc.’s Form 10-Q/A for the quarter ended September 30, 2005, filed January 10, 2006, File No. 001-15565.
(t)
Filed with SEMCO Energy, Inc.’s Form 10-K for the fiscal year ended December 31, 2005, filed March 14, 2006, File No. 001-15565.
(u)
Filed with SEMCO Energy, Inc.’s Form 8-K filed April 25, 2006, File No. 001-15565.
(v)
Filed with SEMCO Energy, Inc.’s Form 8-K filed May 26, 2006, File No. 001-15565.
(w)
Filed with SEMCO Energy, Inc.’s Form 8-K filed October 10, 2006, File No. 001-15565.
(x)
Filed with SEMCO Energy, Inc.’s Form 8-K filed October 17, 2006, File No. 001-15565.
(y)
Filed with SEMCO Energy, Inc.’s Form 8-K filed November 2, 2006, File No. 001-15565.
(z)
Filed with SEMCO Energy, Inc.’s Form 10-Q for the quarter ended September 30, 2006, filed November 6, 2006, File No. 001-15565.
(aa)
Filed with SEMCO Energy, Inc.’s Form 8-K filed November 20, 2006, File No. 001-15565.
(bb)
Filed with SEMCO Energy, Inc.’s Form 8-K filed December 7, 2006, File No. 001-15565.
(cc)
Filed with SEMCO Energy, Inc.’s Form 8-K filed January 11, 2007, File No. 001-15565.
(dd)
Filed with SEMCO Energy, Inc.’s Form 8-K filed February 23, 2007, File No. 001-15565.
(ee)
Filed with SEMCO Energy, Inc.’s Form 8-K filed February 28, 2007, File No. 001-15565.
(ff)
To be filed in April 2007, pursuant to Rule 14a-6 of the Exchange Act, File No. 001-15565.
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.
Semco Energy, Inc.
By
/s/ George A. Schreiber, Jr.
George A. Schreiber, Jr.
President and Chief Executive Officer
(principal executive officer)
Date: March 13, 2007
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 dates indicated.