UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
ý ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
o TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-3551
EQUITABLE RESOURCES, INC.
(Exact name of registrant as specified in its charter)
PENNSYLVANIA |
|
25-0464690 |
|
(State or other jurisdiction of |
|
(IRS Employer |
|
|
|
|
|
One Oxford Centre, Suite 3300 |
|
15219 |
|
(Address of principal executive offices) |
|
(Zip Code) |
Registrant’s telephone number, including area code: (412) 553-5700
Securities registered pursuant to Section 12(b) of the Act:
|
Title of each class |
|
Name of each exchange on which registered |
|
Common Stock, no par value |
|
New York Stock Exchange |
|
|
|
|
|
Preferred Stock Purchase Rights |
|
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter periods that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b–2 of the Exchange Act).
Yes ý No o
The aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2004: $3,152,912,692
The number of shares outstanding of the issuer’s classes of common stock as of January 31, 2005: 61,043,334
The information required by Part III, portions of Item 10 and Item 12, and Items 11 and 14 are incorporated by reference from the Proxy Statement for the Company’s Annual Meeting of Stockholders to be held on April 13, 2005, which Proxy Statement will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2004, except for the Performance Graph, Report of the Compensation Committee on Executive Compensation, and Report of the Audit Committee.
2
Forward-Looking Statements
Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report specifically include the expectations of future plans, objectives, cost savings, growth and anticipated financial and operational performance of the Company and its subsidiaries, including statements regarding the strategy for hedging production and optimizing storage capacity, including the approximate volumes and prices hedged and possible changes in the event of continued high NYMEX pricing; the Company’s identification of growth opportunities and its ability to execute its operational strategies in competitive environments; the belief that environmental expenditures will not be significantly different in nature or amount in the future and will not have a material effect on the Company’s financial position or results of operations; the adequacy of legal reserves and therefore the belief that the ultimate outcome of any matter currently pending will not materially affect the financial position of the Company; the anticipation that dividends will continue to be paid on a regular quarterly basis; the amount and timing of estimated capital expenditures; the belief that the Company has sources of liquidity sufficient to meet its needs; the possible impact of inflation and the effect of changing prices; the projected timing and amount of the Company’s contractual obligations; the estimated maximum payable in respect of outstanding guaranties; the Company’s approach to compensation, including its ultimate obligation in respect of the 2003 Executive Performance Incentive Program which is based in part upon an expected price per share at year end; the expected rate of return and discount rate associated with the Company’s pension expense and pension funding obligations and the effect of changes in such rates; the estimated amount of cash contributions to the pension plan; the deductibility for Federal tax purposes of the capital loss on the Company’s previous sale of its midstream operations; the timing and amount of expenses to be incurred as a consequence of relocation to new office space and of the increased efficiencies resulting from the relocation; the belief that implementation of Equitable Gas’ customer information and billing system will help improve collection efforts; the ultimate outcome of pending and anticipated rate cases, regulatory reviews and audits and other regulatory action, including the amounts that the Company expects to recover or incur as a consequence of such events; the change in strategy and related operational matters at the Supply segment, including the anticipated number of wells to be drilled, the number of drilling locations on unproved properties, the effectiveness of infrastructure improvement projects, anticipated volumes, the Company’s ability to raise gathering rates and the impact of the expected sale of certain non-core producing properties; the expected amount, timing, and the source of payment for, plugging and abandonment obligations; the ability to divest international projects on an accelerated schedule; the pace at which the performance contracting business can be resumed; the likelihood of resolution of issues relating to the Jamaican energy infrastructure project and the bankruptcy of ERI JAM, LLC; the anticipated increase in liquidity associated with the merger of Westport Resources Corporation and Kerr-McGee Corporation and the financial impact of the hedges on the Company’s Kerr-McGee Stock; the other estimates incorporated into the Company’s critical accounting estimates and the expected impact of new accounting pronouncements. A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, the following: weather conditions, commodity prices for natural gas and crude oil and associated hedging activities, availability and cost of financing, changes in interest rates, the needs of the Company with respect to liquidity, curtailments or disruptions in production, the substance, timing and availability of regulatory and legislative action, timing and extent of the Company’s success in acquiring utility companies and natural gas and crude oil properties, the ability of the Company to discover, develop and produce reserves, the ability of the Company to acquire and apply technology to its operations, the impact of competitive factors on profit margins in various markets in which the Company competes, the ability of the Company to negotiate satisfactory collective bargaining agreements with its union employees, changes in accounting rules or their interpretation, and other factors discussed in other reports filed by the Company from time to time. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.
3
Equitable Resources, Inc. (Equitable Resources or Equitable or the Company) is an integrated energy company, with an emphasis on Appalachian area natural gas supply activities including production and gathering, and natural gas distribution and transmission. The Company’s operations also include providing energy efficiency solutions nationally, but primarily in the eastern and western coastal regions of the United States. The Company and its subsidiaries offer energy (natural gas, and a limited amount of natural gas liquids and crude oil) products and services to wholesale and retail customers through three business segments: Equitable Utilities, Equitable Supply and NORESCO. The Company and its subsidiaries had approximately 1,500 employees at the end of 2004.
The Company was formed under the laws of Pennsylvania by the consolidation and merger in 1925 of two constituent companies, the older of which was organized in 1888. In 1984, the corporate name was changed to Equitable Resources, Inc.
The Company makes certain filings with the Securities and Exchange Commission (SEC), including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through its website, www.eqt.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W. Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at www.sec.gov. The Company’s annual report to shareholders, press releases and recent analyst presentations are also available on the Company’s website.
Equitable Utilities
Equitable Utilities contains both regulated and nonregulated operations. The regulated group consists of the distribution and interstate pipeline operations, while the nonregulated group is involved in the non-jurisdictional marketing of natural gas, risk management activities for Equitable Utilities and Equitable Supply and the sale of energy-related products and services. Equitable Utilities generated approximately 36% of the Company’s net operating revenues in 2004.
Natural Gas Distribution
Equitable Utilities’ distribution operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory for Equitable Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales (also referred to as “farm tap” service as the customer is served directly from a well or gathering pipeline) in eastern Kentucky and in West Virginia. The distribution operations provide natural gas services to approximately 276,300 customers, comprising 257,400 residential customers and 18,900 commercial and industrial customers. Equitable Gas also operates a small gathering system in Pennsylvania.
Equitable Gas’ natural gas supply portfolio includes short-term purchases (purchases to be delivered in one month or less), medium-term purchases (purchases to be delivered in less than one year but more than one month) and long-term purchases (purchases to be delivered in more than one year). These natural gas supply contracts are obtained from various sources including purchases from major and independent producers in the Gulf Coast, purchases from local producers in the Appalachian area and purchases from gas marketers (including an affiliate of Equitable Gas). Equitable Gas’ supply purchases include various pricing mechanisms, ranging from fixed prices to several different index-related prices. These supply purchase contracts qualify as “normal purchases and normal sales” of natural gas.
Because most of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 70% of calendar year 2004 revenues occurring during the winter heating season (January–March, November–December). Significant quantities of purchased natural gas are placed in underground storage inventory during off-peak season to accommodate higher customer demand during the winter heating season.
4
Interstate Pipeline
The interstate pipeline operations of Equitable Utilities include the natural gas transmission, storage and gathering activities of Equitrans, L.P. (Equitrans) and Carnegie Interstate Pipeline Company (Carnegie Pipeline). Effective, January 1, 2004, Equitrans and Carnegie Pipeline merged, with Equitrans surviving the merger. The interstate pipeline operations offer gas transportation, storage, gathering and related services to affiliates and third parties in the Northeastern United States including, but not limited to, Dominion Resources, Inc.; Public Service Electric and Gas Company; Keyspan Corporation; NiSource, Inc.; PECO Energy Company; and Amerada Hess Corporation. In 2004, approximately 68% of transportation volumes and approximately 77% of revenues were from affiliates.
The present regulatory environment is designed to increase competition in the natural gas industry. This environment has created a number of opportunities for pipeline companies to expand services and serve new markets. The Company has taken advantage of selected market opportunities by concentrating on Equitrans’ underground storage facilities and interconnections with five major interstate pipelines – Texas Eastern Transmission, Columbia Gas Transmission, National Fuel Gas Supply, Tennessee Gas Pipeline and Dominion Transmission. The geographic locations of Equitrans’ storage facilities, coupled with the flexibility provided by these interconnecting pipelines, provides opportunities for Equitrans to access natural gas markets in the Northeastern United States.
Energy Marketing
Equitable Utilities’ unregulated marketing operations include the non-jurisdictional marketing of natural gas at Equitable Gas, marketing and risk management activities at Equitable Energy, LLC (Equitable Energy), and the sale of energy-related products and services by Equitable Homeworks. Equitable Energy purchases, stores and sells natural gas at both the retail and wholesale level, primarily in the Appalachian and mid-Atlantic regions. Services and products offered by the marketing operations include commodity procurement and delivery, physical natural gas management operations and control, and customer support services to the Company’s natural gas customers. In 2001, Equitable Gas received approval from the Pennsylvania Public Utility Commission (PA PUC) to implement a performance-based incentive that provides to customers a purchased gas cost credit which is fixed in amount, while enabling Equitable Gas to retain all revenues in excess of the credit obtained through more effective management of upstream interstate pipeline capacity. This performance-based incentive provides an opportunity for Equitable Gas to make short-term releases of unutilized pipeline capacity for a fee and to participate in the bundling of gas supply and pipeline capacity for “off-system” sales. An “off-system” sale involves the purchase and delivery of gas to a customer at mutually agreed-upon points on facilities not owned by the Company. These revenues are recorded with Equitable Utilities’ non-jurisdictional operations.
The Company also engages in trading and risk management activities with the objective of limiting the Company’s exposure to shifts in market prices and optimizing the use of the Company’s assets described above. Equitable Energy uses asset management to hedge projected production, to optimize storage capacity assets through trading activities and to perform risk management services for large industrial customers.
Rates and Regulation
Equitable Utilities’ distribution rates, terms of service, contracts with affiliates and issuance of securities are subject to comprehensive regulation by the PA PUC. The distribution rates, terms of service and contracts with affiliates are also subject to comprehensive regulation by the Public Service Commission of West Virginia, and the distribution rates are subject to regulation by the Kentucky Public Service Commission. Pipeline safety is generally regulated by the rules of the U.S. Department of Transportation and/or by the state regulatory commissions. The U.S. Occupational Safety and Health Administration, as well as its state level counterparts, also imposes certain additional safety regulations on the operations of Equitable Utilities.
The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and the sale for resale of natural gas, including transportation rates, storage tariffs and various other matters, are subject to federal regulation, primarily by the Federal Energy Regulatory Commission (FERC). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation
5
of natural gas. Some of the trading activities of the energy marketing operations are subject to regulation by, among others, the Commodity Futures Trading Commission (CFTC), the FERC, and the PA PUC.
For additional discussion of regulatory matters involving Equitable Utilities, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (MD&A) and Note 11 to the Company’s consolidated financial statements.
Competitive Environment
Equitable Gas operates in areas with varying service area rules, including state utility commission exclusively certificated service areas, and non-exclusive service territories in competitive areas. Additionally, competitive local distribution companies exist within Equitable Gas’ service area. Western Pennsylvania is one of the few regions in the United States where multiple local distribution companies compete for both new and existing customers.
Equitrans will be experiencing significant competitive challenges over the next few years as 95% of the pipeline’s firm contracts expire in calendar year 2006 and the remaining 5% expire in 2007. Equitrans’ ability to respond to these competitive challenges will be influenced, in part, by the ultimate resolution of its recently filed rate case.
The large industrial market is extremely competitive resulting in very low realized margins. However, fluctuations in industrial demand do not have a significant impact on the Company’s financial results.
Equitable Supply
Equitable’s production business develops, produces and sells natural gas and, to a limited extent, crude oil and its associated by-products, with operations in the Appalachian region of the United States. Its natural gas gathering activity consists of gathering the Company’s and third party gas and some processing and sales of natural gas liquids. Equitable Supply generated approximately 58% of the Company’s net operating revenues in 2004.
Production
Equitable’s production business, operating through Equitable Production Company and several smaller affiliates (referred to collectively as Equitable Production), is among the largest owners of proved natural gas reserves in the Appalachian Basin. Equitable Production currently operates approximately 12,600 producing wells in the Appalachian Basin. As of December 31, 2004, the Company estimated its total proved reserves to be 2,109 billion cubic feet equivalent (Bcfe), including proved undeveloped reserves of 477 Bcfe.
The Company’s reserves are located entirely in the Appalachian Basin. The Appalachian Basin is characterized by wells with comparatively low rates of annual decline in production (wells generally produce for periods longer than 50 years), low production costs per well and high British thermal unit (Btu), or energy, content. For operational and commercial reasons, some of the gas produced is processed to allow heavier hydrocarbon (propane, butane and ethane) streams to be stripped and sold separately. Within certain limits, the Company can vary the amount of the hydrocarbons extracted. This can cause the conversion rate between energy content (measured in Btu) to volumes (measured in million cubic feet equivalent (MMcfe)) to vary. Once drilled and completed, wells in the Appalachian Basin typically have low ongoing operating and maintenance requirements. Rates of production are low in comparison to other geographic locations in the United States. Many of the Company’s wells have been producing for decades, and in some cases since the early 1900’s. Reserve estimates for properties with long production histories are generally more reliable than estimates for properties with shorter production histories.
Management believes that virtually all of the Company’s wells are low risk development wells in part because they are drilled to relatively shallow depths ranging from 1,000 to 7,000 feet below the surface. Many of these wells are completed in more than one producing formation, including coal formations in certain areas, and production from these formations may be commingled.
In the Appalachian Basin during 2004, Equitable Production drilled 314 gross wells (246 net wells) at a success rate of 100%. Drilling was concentrated within Equitable’s core areas of southwest Virginia, southeast Kentucky and southern West Virginia. This activity resulted in 14.7 million cubic feet (MMcf) per day of gas sales
6
and proved developed reserve additions of 79 Bcfe. The 79 Bcfe of proved developed reserve additions include approximately 17 billion cubic feet (Bcf) of proved developed extensions, discoveries and other additions that were not previously classified as undeveloped. The remaining 62 Bcfe of proved developed reserve additions relate to proved undeveloped reserves that were transferred to proved developed reserves.
Equitable Production currently has an inventory of 3.5 million gross acres, of which approximately 72% is considered undeveloped. As of December 31, 2004, the Company estimated the proved undeveloped reserves of the underlying leases and fee interests to be 477 Bcfe from approximately 1,616 gross proved undeveloped drilling locations (1,441 net proved undeveloped drilling locations). In the last three years, Equitable Production has completed substantially all of the wells it has drilled. Additionally, given the fact that the Company has developed proved undeveloped reserves of 62 Bcfe and 88 Bcfe during 2004 and 2003, respectively, and that the Company’s plans include developing similar levels of proved undeveloped reserves going forward, the Company believes that the 477 Bcfe of proved undeveloped reserves will be developed in a reasonable period of time, currently estimated to be four years.
Gathering
At December 31, 2004, Equitable Gathering was comprised of Kentucky West Virginia Gas Company, LLC, Equitable Field Services LLC, Equitable Gathering, LLC and the gathering operations of Equitable Production Company (referred to collectively as Equitable Gathering).
Equitable Gathering derives its revenues from charges it assesses to customers on a gathering and production pipeline system in the Appalachian Basin. The system includes approximately 9,000 miles of pipeline located throughout West Virginia, eastern Kentucky, southwestern Virginia, eastern Ohio and portions of Pennsylvania. Over 80% of the volumes through the pipeline system interconnect with three major interstate pipelines: Columbia Gas Transmission, East Tennessee Natural Gas Company, and Dominion Transmission. The gathering system also maintains interconnects with Equitrans, the Company’s interstate transmission affiliate that affords access to natural gas markets in Southwestern Pennsylvania and the Northeastern United States. Maintaining these interconnects provides the Company with access to multiple markets and the flexibility to redirect deliveries when flow interruptions occur.
Gathered sales volumes for 2004 totaled 127.3 Bcf, of which approximately 49% related to affiliate sales volumes (primarily the gathering of Equitable Production’s equity sales volumes), 35% related to third party volumes, and the remainder related to volumes in which interests were sold by the Company but which the Company still operates for a fee. Approximately 69% of the Company’s 2004 gathering revenues were from affiliates. Due to increased operating and capital costs, Equitable Gathering is currently charging below cost to its gathering customers. Equitable Gathering will pursue recovery of the increased cost of providing services through the rates it charges to its customers.
Effective January 1, 2005, the Company reorganized its gathering business, subject to receipt of applicable approvals. This reorganization is consistent with the Company’s initiative to separate its production and gathering businesses in order to ensure that all gathering costs are appropriately captured and gathering rates charged to customers include a proper return. Certain gathering systems are subject to regulation.
Competitive Environment
Equitable Supply’s commercial operations are focused on selling natural gas at a high level of reliability of delivery. Equitable Supply does not actively engage in any activities to differentiate its products and therefore receives market-based pricing. Because the Appalachian Basin is geographically located in the Northeastern United States, gas prices are generally higher than those prices for gas located in the Gulf region of the country given the differences in supply and demand of natural gas in those areas and the relative cost to transport to customers in the Northeast. As a consequence, Equitable Supply’s location provides a price advantage over those companies located in the Gulf region of the country.
The Company has noticed some relative value erosion of Mid-Atlantic basis as a result of new base load gas supplies. Basis is the difference between the NYMEX futures contracts at Henry Hub and the cash price at other
7
market points. If the rate of supply growth in Appalachia exceeds the Mid-Atlantic region’s growth in demand, there may be further weakening in basis, especially in the summer months. At this time, this erosion has not had a significant impact on the Company’s results.
The combination of its long-lived production, low drilling costs, high drilling completion rates at shallow depths and proximity to natural gas markets has had a substantial impact on the development of the Appalachian Basin, resulting in a highly fragmented operating environment. In 2004, Kentucky, Virginia and West Virginia had approximately 3,500 independent operators and approximately 94,000 producing natural gas and oil wells. Also, the previous availability of non-conventional fuels tax credit incentives has resulted in extensive drilling in the shallow formations with these low technical risk characteristics.
Hedging Activities
The Company enters into hedging contracts with respect to forecasted natural gas production and third party purchases and sales at specified prices for a specified period of time. The Company’s hedging strategy and information regarding derivative instruments used are outlined in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Notes 1 and 3 to the consolidated financial statements.
NORESCO
NORESCO provides an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency. The segment’s activities comprise performance contracting, energy efficiency programs, combined heat and power, and central boiler/chiller plant development, design, construction, ownership and operation. NORESCO’s customers include governmental, military, institutional, commercial and industrial end-users. NORESCO provided approximately 6% of the Company’s net operating revenues in 2004.
The segment’s performance contracting activities include “turnkey” solutions for clients to implement energy efficiency and conservation projects. Guaranteed energy savings are used to pay for installation of new energy-efficient equipment and systems. Within the performance contracting solution, NORESCO provides engineering analysis, project management, construction, financing, operations and maintenance, and energy savings measurement and verification. Typically, at any given time, NORESCO has a range of 30 to 60 on-going construction contracts, depending on the size and mix of the projects, and approximately 150 to 250 on-going operations and maintenance projects.
The segment’s energy infrastructure activities provide clients with development, construction and operation and maintenance services for cogeneration, central plant, and private power generation facilities in the United States. These projects serve a diverse clientele including governmental, institutional, commercial and industrial customers and utilities. NORESCO’s capabilities offer a “turnkey” approach to energy infrastructure programs including project development, equipment selection, fuel procurement, environmental permitting, construction, financing and operations and maintenance.
Competitive Environment
NORESCO operates in a highly competitive market segment, with competitors that include affiliates of large energy companies and building automation controls companies.
Many performance contracting and energy infrastructure projects require that NORESCO provide a surety bond in advance of being awarded a contract. NORESCO’s continued ability to obtain adequate bonding could affect NORESCO’s business.
On September 30, 2003, the enabling legislation for the performance contracting work that NORESCO performs for the federal government under the Department of Energy contracts lapsed. On October 28, 2004, the President signed legislation extending the contracting period for performance contracting at federal government facilities through October 2006.
8
Foreign Operations
NORESCO has investments in nonconsolidated partnerships located in foreign countries, specifically in Jamaica, Panama and Costa Rica. These investments represent equity ownership interests in independent power plant projects.
The Company reviewed its equity investment related to Petroelectrica de Panama LDC, an independent power plant in Panama, during the fourth quarter of 2003. As a result of the analysis performed, an impairment of $11.1 million in the fourth quarter of 2003 was recorded which represented the full value of NORESCO’s equity investment in the project. The plant has been dismantled and the proceeds from the sale of the plant’s engines will be used to cover the costs of remediation and final closure in 2005.
During the second quarter of 2004, several negative circumstances caused the Company to evaluate its international investments for additional impairments and to accelerate its plans to exit the international generation business. See “Equity in Nonconsolidated Investments” in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information.
In January 2005, the Company sold its interest in Compania Hidroelectrica Dona Julia, S.D.R. Ltd., a Costa Rican electric generation project, to a third party purchaser and recorded a slight gain on the sale in 2005. The Company intends to exit its remaining international independent power plant projects and is actively evaluating alternatives for the sale and disposal of these international assets.
Composition of Segment Operating Revenues
Presented below are operating revenues as a percentage of total operating revenues for each class of products and services representing greater than 10% of each of the three business segments during the years 2002 through 2004. In 2004 and 2003, intercompany segment eliminations are recorded against marketed natural gas sales. 2002 percentages have been reclassified for comparative purposes.
|
|
|
2004 |
|
2003 |
|
2002 |
|
|
Equitable Utilities: |
|
|
|
|
|
|
|
|
Residential natural gas sales |
|
25 |
% |
27 |
% |
21 |
% |
|
Marketed natural gas |
|
20 |
% |
15 |
% |
22 |
% |
|
Equitable Supply: |
|
|
|
|
|
|
|
|
Produced natural gas equivalents |
|
25 |
% |
24 |
% |
20 |
% |
|
NORESCO: |
|
|
|
|
|
|
|
|
Energy service contracting |
|
12 |
% |
16 |
% |
18 |
% |
Financial Information About Segments
See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 to the consolidated financial statements for financial information by business segment.
Financial Information About Geographic Areas
All but an insignificant amount of the Company’s assets and operations are located in the continental United States.
Environmental
See “Contingent Liabilities and Commitments” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 22 to the consolidated financial statements for information regarding environmental matters.
9
Principal facilities are owned by the Company’s business segments, with the exception of various office locations and warehouse buildings, which are leased. A limited amount of equipment is also leased. The majority of the Company’s properties are located on or under (1) public highways under franchises or permits from various governmental authorities, or (2) private properties owned in fee, or occupied under perpetual easements or other rights acquired for the most part without examination of underlying land titles. The Company’s facilities have adequate capacity, are well maintained and, where necessary, are replaced or expanded to meet operating requirements.
Equitable Utilities. This segment owns and operates natural gas distribution properties as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky. The segment also owns and operates underground storage, transmission, and gathering facilities in Pennsylvania and West Virginia.
The distribution operations consist of approximately 4,100 miles of pipe in Pennsylvania, West Virginia and Kentucky. The interstate pipeline operations consist of approximately 1,500 miles of transmission, storage, and gathering lines, and interconnections with five major interstate pipelines. The interstate pipeline system stretches throughout north central West Virginia and southwestern Pennsylvania. Equitrans has fifteen natural gas storage reservoirs with approximately 500 MMcf per day of peak delivery capability and 59 Bcf of storage capacity of which 27 Bcf is working gas. These storage reservoirs are clustered, with eight in northern West Virginia and seven in southwestern Pennsylvania. Equitrans has conducted geologic assessment and volumetric analyses of its storage reservoirs, in an effort to enhance its storage capacity and deliverability capability. The analyses, which were completed in late 2003, indicated the need to replenish certain base gas volumes. Equitrans intends to address the replenishment of these volumes in conjunction with the resolution of its rate case which is currently pending before the FERC.
Equitable Utilities’ primary office space is located in leased office space in Pittsburgh, Pennsylvania. This segment leases other office space and equipment in Pennsylvania that is not significant to the operations of the segment.
Equitable Supply. This business segment owns or controls all of the Company’s acreage of proved developed and undeveloped natural gas and oil production properties. The segment also owns and operates approximately 9,000 miles of gathering pipelines and 185 compressor units comprising 119 compressor stations with approximately 112,000 hp of installed capacity, as well as other general property and equipment. This segment’s production and gathering properties are located in the Appalachian Basin, specifically Kentucky, Ohio, Pennsylvania, Virginia, and West Virginia. Information relating to Company estimates of natural gas and crude oil reserves and future net cash flows is provided in Note 27 (unaudited) to the consolidated financial statements.
Natural Gas and Crude Oil Production:
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Natural Gas: |
|
|
|
|
|
|
|
|||
|
MMcf produced |
|
72,226 |
|
69,422 |
|
67,171 |
|
|||
|
Average well-head sales price per Mcfe sold (net of hedges) |
|
$ |
4.45 |
|
$ |
3.91 |
|
$ |
3.47 |
|
|
MMcfe operated (a) |
|
94,625 |
|
92,538 |
|
91,793 |
|
|||
|
MMcfe gathered (b) |
|
127,339 |
|
126,674 |
|
123,581 |
|
|||
|
Crude Oil: |
|
|
|
|
|
|
|
|||
|
Thousands of barrels produced |
|
83 |
|
83 |
|
127 |
|
|||
|
Average sales price per barrel |
|
$ |
37.38 |
|
$ |
26.08 |
|
$ |
20.78 |
|
(a) Includes produced volumes and volumes from properties the Company operates for third parties for a fee.
(b) Includes operated volumes as well as volumes gathered as a service performed for third parties for a fee.
10
Average production cost, including severance taxes (lifting cost), of natural gas and crude oil during 2004, 2003, and 2002 was $0.583, $0.499, and $0.387 per Mcf equivalent, respectively.
|
|
|
Natural Gas |
|
|
|
Oil |
|
|
Total productive wells at December 31, 2004: |
|
|
|
|
|
|
|
|
Total gross productive wells |
|
12,606 |
|
|
|
18 |
|
|
Total net productive wells |
|
7,979 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
Total acreage at December 31, 2004: |
|
|
|
|
|
|
|
|
Total gross productive acres |
|
|
|
988,000 |
|
|
|
|
Total net productive acres |
|
|
|
928,720 |
|
|
|
|
Total gross undeveloped acres |
|
|
|
2,557,719 |
|
|
|
|
Total net undeveloped acres |
|
|
|
2,398,427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of net productive and dry exploratory and development wells drilled: |
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
2003 |
|
2002 |
|
|
Exploratory wells: |
|
|
|
|
|
|
|
|
Productive |
|
— |
|
— |
|
— |
|
|
Dry |
|
— |
|
— |
|
— |
|
|
Development wells: |
|
|
|
|
|
|
|
|
Productive |
|
246.5 |
|
354.8 |
|
338.4 |
|
|
Dry |
|
— |
|
— |
|
1.0 |
|
No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company’s estimated total reserves.
Substantially all sales are delivered to several large interstate pipelines on which the Company leases capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.
Equitable Supply leases office space in Pittsburgh, Pennsylvania and Charleston, West Virginia. The segment also leases some compressors in Pennsylvania, West Virginia, Virginia and Kentucky. This segment leases other office space and equipment in Pennsylvania, West Virginia, Virginia and Kentucky that is not significant to the operation of the segment.
NORESCO. NORESCO is based in Westborough, Massachusetts, and leases offices in 20 locations throughout the United States. The following table provides a summary of the number of leased offices by state:
|
State |
|
Number of Offices |
|
California |
|
4 |
|
Colorado |
|
1 |
|
Connecticut |
|
1 |
|
Florida |
|
1 |
|
Georgia |
|
1 |
|
Hawaii |
|
1 |
|
Kentucky |
|
1 |
|
Massachusetts |
|
2 |
|
New Hampshire |
|
1 |
|
New York |
|
1 |
|
North Carolina |
|
1 |
|
Pennsylvania |
|
1 |
|
Texas |
|
1 |
|
Virginia |
|
2 |
|
Washington |
|
1 |
11
Headquarters. The headquarters is located in leased office space in Pittsburgh, Pennsylvania.
The Company has entered into a long-term lease with Continental Real Estate Companies (Continental) to occupy office space in a building at the North Shore in Pittsburgh. This action will help consolidate the Company’s administrative operations. Continental is constructing and will own the office building, which is expected to be completed in 2005.
After an extended period of troubled operations, ERI JAM, LLC, a subsidiary that holds the Company’s interest in EAL/ERI Cogeneration Partners LP, an international infrastructure project located in Jamaica, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. In the third quarter 2003, ERI JAM, LLC transferred control of the international infrastructure project under the partnership agreement to the other non-affiliate general partner. The international infrastructure project was deconsolidated in accordance with Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.” In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM LLC as Debtor-in-Possession in the Chapter 11 case. EAL, an affiliate of JBG, is a limited partner in EAL/ERI Cogeneration Partners LP. In October 2003, JBG and EAL also filed a multi-count complaint seeking damages against Equitable and certain of its affiliates in U.S. District Court (Western District of Pennsylvania) alleging breach of contract, tortious interference with contractual relations, negligence and a variety of related claims with respect to the operation and management of EAL/ERI Cogeneration Partners LP. Equitable filed a Motion to Dismiss in September 2004, and subsequently agreed in principle with JBG and EAL to settle the litigation. The parties are currently negotiating the terms of a settlement agreement.
In addition, in the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the Company’s security holders during the last quarter of its fiscal year ended December 31, 2004.
12
Executive Officers of the Registrant (as of February 25, 2005)
|
Name and Age |
|
Current Title (Year Initially Elected an |
|
Business Experience |
|
John A. Bergonzi (52) |
|
Vice President and Corporate Controller (January 2003) |
|
Elected to present position January 2003; Corporate Controller and Assistant Treasurer from December 1995 to December 2002. |
|
|
|
|
|
|
|
Philip P. Conti (45) |
|
Vice President, Chief Financial Officer and Treasurer (August 2000) |
|
Elected to present position January 2005; Vice President, Finance and Treasurer from August 2000 to January 2005; Director of Planning and Development from June 1998 to August 2000. |
|
|
|
|
|
|
|
Randall L. Crawford (42) |
|
Vice President (January 2003) |
|
Elected to present position January 2003; President, Equitable Gas Company from January 2003 to present; Executive Vice President, Equitable Gas Company from November 2000 to December 2002; Senior Vice President, Equitable Gas Company from December 1999 to November 2000. |
|
|
|
|
|
|
|
Murry S. Gerber (52) |
|
Chairman, President and Chief Executive Officer (June 1998) |
|
Elected to present position May 2000; President and Chief Executive Officer from June 1, 1998 to present. |
|
|
|
|
|
|
|
Joseph E. O’Brien (52) |
|
Vice President (January 2001) |
|
Elected to present position January 2001; President, NORESCO, LLC from January 2000 to present; Senior Vice President, Construction & Engineering from June 1993 to January 2000. |
|
|
|
|
|
|
|
Johanna G. O’Loughlin (58) |
|
Senior Vice President, General Counsel and Secretary (December 1996) |
|
Elected to present position January 2002; Vice President, General Counsel and Secretary from May 1999 to January 2002. |
13
|
Name and Age |
|
Current Title (Year Initially Elected an |
|
Business Experience |
|
Charlene Petrelli (43) |
|
Vice President, Human Resources (January 2003) |
|
Elected to present position January 2003; Director of Corporate Human Resources from October 2000 to December 2002; Director of Human Resources, Fisher Scientific International, Inc. (a provider of equipment, supplies, and services for the clinical laboratory and scientific research markets) from December 1999 to September 2000. |
|
|
|
|
|
|
|
David L. Porges (47) |
|
Vice Chairman and
Executive |
|
Elected to present position January 2005; Executive Vice President and Chief Financial Officer from February 2000 to January 2005; Senior Vice President and Chief Financial Officer from July 1998 to January 2000. |
|
|
|
|
|
|
|
Diane L. Prier (45) |
|
Vice President (December 2004) |
|
Elected to present position December 2004; President, Equitable Production Company from December 2004 to present; President, Williams Alaska Petroleum, Inc. (a subsidiary of The Williams Companies, a company engaged in natural gas gathering, storage, processing and transportation, as well as oil and gas exploration and production) from August 2001 to April 2004; Vice President - Rockies Midstream Operations, The Williams Companies from March 1998 to July 2001. |
Messrs. Gerber and Porges have executed employment agreements with the Company. All executive officers serve at the pleasure of the board. Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified.
14
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’s common stock is listed on the New York Stock Exchange and the Philadelphia Stock Exchange. The Company’s Board of Directors has approved the delisting of the common stock from the Philadelphia Stock Exchange, and that process is expected to be completed during the first quarter of 2005. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions, and the dividends declared and paid per share, are summarized as follows (in U.S. dollars per share):
|
|
|
2004 |
|
2003 |
|
||||||||||||||
|
|
|
High |
|
Low |
|
Dividend |
|
High |
|
Low |
|
Dividend |
|
||||||
|
1st Quarter |
|
$ |
44.92 |
|
$ |
42.10 |
|
$ |
0.300 |
|
$ |
37.90 |
|
$ |
34.44 |
|
$ |
0.170 |
|
|
2nd Quarter |
|
51.75 |
|
43.99 |
|
0.380 |
|
42.00 |
|
37.08 |
|
0.200 |
|
||||||
|
3rd Quarter |
|
54.49 |
|
49.89 |
|
0.380 |
|
41.65 |
|
37.85 |
|
0.300 |
|
||||||
|
4th Quarter |
|
61.18 |
|
53.36 |
|
0.380 |
|
43.42 |
|
39.95 |
|
0.300 |
|
||||||
As of February 16, 2005, there were approximately 4,304 shareholders of record of the Company’s common stock.
The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, the Company’s results of operations and financial condition and other factors. The Company is targeting dividend growth at a rate similar to the rate of earnings per share growth. Based on currently foreseeable market conditions, the Company anticipates dividends will continue to be paid on a regular quarterly basis.
The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended December 31, 2004.
|
Period |
|
Total |
|
Average |
|
Total number of |
|
Maximum number |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 2004 (October 1 – October 31) |
|
6,900 |
|
$ |
53.48 |
|
6,900 |
|
3,269,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 2004 (November 1 – November 30) |
|
353,516 |
|
$ |
57.06 |
|
348,400 |
|
2,921,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 2004 (December 1 – December 31) |
|
144,700 |
|
$ |
58.44 |
|
144,700 |
|
2,776,700 |
|
|
Total |
|
505,116 |
|
|
|
500,000 |
|
|
|
|
(a) Includes 5,116 shares delivered in exchange for the exercise of options to cover option cost and tax withholding. All other purchases were open market purchases made pursuant to the Company’s publicly disclosed repurchase program. The Company routinely enters into “10b5-1 plans,” or trading plans, to facilitate continuity of its share repurchase program through earnings blackout periods.
(b) Equitable’s Board of Directors has authorized a share repurchase program with a current maximum of 21.8 million shares and no expiration date. The program was initially publicly announced on October 7, 1998 with subsequent amendments announced on November 12, 1999, July 20, 2000 and April 15, 2004.
15
Item 6. Selected Financial Data
|
|
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
|||||
|
|
|
(Thousands except per share amounts) |
|
|||||||||||||
|
|
|
|
|
|||||||||||||
|
Operating revenues (a) |
|
$ |
1,191,609 |
|
$ |
1,047,277 |
|
$ |
1,069,068 |
|
$ |
1,109,334 |
|
$ |
1,036,531 |
|
|
Income from continuing operations before cumulative effect of accounting change (b) |
|
$ |
279,854 |
|
$ |
173,557 |
|
$ |
150,626 |
|
$ |
151,808 |
|
$ |
106,173 |
|
|
Income from continuing operations before cumulative effect of accounting change per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Basic |
|
$ |
4.54 |
|
$ |
2.80 |
|
$ |
2.40 |
|
$ |
2.36 |
|
$ |
1.63 |
|
|
Diluted |
|
$ |
4.44 |
|
$ |
2.74 |
|
$ |
2.36 |
|
$ |
2.30 |
|
$ |
1.60 |
|
|
Total assets |
|
$ |
3,196,546 |
|
$ |
2,947,359 |
|
$ |
2,436,891 |
|
$ |
2,518,747 |
|
$ |
2,424,914 |
|
|
Long-term debt |
|
$ |
628,351 |
|
$ |
653,414 |
|
$ |
471,250 |
|
$ |
271,250 |
|
$ |
287,789 |
|
|
Preferred trust securities |
|
$ |
— |
|
$ |
— |
|
$ |
125,000 |
|
$ |
125,000 |
|
$ |
125,000 |
|
|
Cash dividends declared per share of common stock |
|
$ |
1.44 |
|
$ |
0.97 |
|
$ |
0.67 |
|
$ |
0.63 |
|
$ |
0.59 |
|
(a) Operating revenues for years prior to 2002 have been reclassified to reflect all gains and losses associated with the Company’s energy trading activities on a net basis as required by the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) in EITF No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and No. 00-17.”
(b) The year ended December 31, 2003 excludes the negative cumulative effect of an accounting change of $3.6 million related to the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.” The year ended December 31, 2002 excludes the negative cumulative effect of accounting change of $5.5 million related to the impairment of goodwill and income from discontinued operations of $9.0 million related to the sale of the Company’s natural gas midstream operations.
See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 4 and 5 to the consolidated financial statements for other matters that affect the comparability of the selected financial data as well as uncertainties that might affect the Company’s future financial condition.
16
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Consolidated Results of Operations
Equitable’s consolidated income from continuing operations before cumulative effect of accounting change for 2004 was $279.9 million, or $4.44 per diluted share, compared with $173.6 million, or $2.74 per diluted share, for 2003, and $150.6 million, or $2.36 per diluted share, for 2002.
The 2004 income from continuing operations before cumulative effect of accounting change increased 61% from 2003 primarily due to the gain recorded as a result of the Westport Resources Corporation (Westport)/Kerr-McGee Corporation (Kerr-McGee) merger as described below. Higher realized selling prices, an increase in sales volumes from production, proceeds received from an insurance settlement, and the gain recorded on the sale of 800,000 Kerr-McGee shares in 2004 also helped to improve 2004 earnings. The improved 2004 earnings were partially offset by additional impairment charges recorded in 2004 related to the Company’s international investments, an increase in the cost of the Company’s Executive Performance Incentive Programs, the gain recorded on the sale of Westport shares in 2003, the costs to settle the cash balance portion of a defined benefit pension plan in 2004, an increase over the prior year in charitable foundation contribution expense, the loss on a 2004 amendment of the Company’s prepaid forward contract, warmer weather in 2004, and an increase in interest expense.
The effective tax rate for the year ended December 31, 2004 was 33.8% compared to 32.0% reported for the same period a year ago. The increase in the Company’s effective tax rate is primarily the result of the one-time permanent tax benefit realized from the 2003 gift of qualified appreciated stock to Equitable Resources Foundation, Inc. which was created by the Company to support development programs in communities where the Company conducts business; the 2004 gift of qualified appreciated stock did not generate a significant permanent book/tax difference as the investment was accounted for as available-for-sale in 2004. See Note 6 to the consolidated financial statements.
The 2003 income from continuing operations before cumulative effect of accounting change increased 15% from 2002 due to an increase in average natural gas prices, gains on the sale of Westport stock, increased equity earnings in Westport prior to the Company’s change in accounting treatment for its investment in Westport, an increase in sales volumes from production, less minority interest expense recognized in 2003 associated with the Company’s ownership in Appalachian Basin Partners, LP (ABP), and an impairment of the Company’s Jamaica power plant recognized in 2002. The improved 2003 earnings were partially offset by an impairment of an equity investment in an independent power plant project located in Panama, costs associated with the 2003 Executive Performance Incentive Program, higher depreciation, depletion and amortization expense resulting from an increase in production volumes and the unit depletion rate, an increase in production and leasehold expenses primarily the result of an increase in severance taxes attributable to higher average natural gas prices and an increase in maintenance and other repairs, an increase in interest expense primarily due to a net increase in the amount of outstanding debt, an increase in benefit and insurance costs and the establishment of Equitable Resources Foundation, Inc.
The effective tax rate for the year ended December 31, 2003 was 32.0% compared to 34.0% reported for the year ended December 31, 2002. The decrease in the Company’s effective tax rate was primarily the result of the permanent tax benefit from the 2003 gift of qualified appreciated stock. See Note 6 to the consolidated financial statements.
Business Segment Results
Business segment operating results are presented in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity earnings from nonconsolidated investments, excluding Westport, minority interest and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments. Certain performance-related incentive costs, pension costs, and administrative costs totaling $45.8 million, $20.4 million and $5.4 million in 2004, 2003 and 2002, respectively, were not allocated to business
17
segments. The increase in 2004 is primarily related to the costs for the Executive Performance Incentive Program more fully described in Note 19 to the consolidated financial statements as well as the costs to settle the cash balance portion of a defined benefit plan more fully described in Note 16 to the consolidated financial statements.
The Company has reconciled the segments’ operating income, equity earnings from nonconsolidated investments, excluding Westport, minority interest and other income, net to the Company’s consolidated operating income, equity earnings from nonconsolidated investment, excluding Westport, minority interest and other income, net totals in Note 2 to the consolidated financial statements. Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note 2. The Company has also reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. Equitable’s management believes that presentation of this information provides useful information to management and investors regarding the financial condition, operations and trends of each of Equitable’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest and income taxes. In addition, management uses these measures for budget planning purposes.
Equitable Utilities
Equitable Utilities’ operations comprise the gathering, sale, and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities.
Natural Gas Distribution
Equitable Utilities’ distribution operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory for Equitable Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales (also referred to as “farm tap” service as the customer is served directly from a well or gathering pipeline) in eastern Kentucky and in West Virginia. The distribution operations provide natural gas services to approximately 276,300 customers, comprising 257,400 residential customers and 18,900 commercial and industrial customers. Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky. Equitable Gas also operates a small gathering system in Pennsylvania, which is not subject to comprehensive regulation.
A Pennsylvania Public Utility Commission (PA PUC) mandated asset service life study was filed with the PA PUC by Equitable Gas in May 2004. This study resulted in an increase in the estimated useful life for Equitable Gas’ distribution main lines and service lines as a result of installing plastic pipe. The PA PUC statutory review period expired in October 2004 with no objection from the PA PUC to modify Equitable Gas’ asset service life study. As a consequence, the useful life of the distribution main lines and service lines was extended in the fourth quarter on a retroactive basis to January 1, 2004, resulting in a decrease in depreciation expense of approximately $3.5 million in 2004. Equitable Gas recorded this depreciation expense adjustment in the fourth quarter of 2004. This adjustment did not have a significant impact upon previously reported information.
Pennsylvania law requires that local distribution companies develop and implement programs to assist low-income customers with paying their gas bills. The costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs. In August 2003, Equitable Gas submitted revisions to those programs for PA PUC approval. The revisions were designed to make participation in the low-income programs more accessible thereby improving participants’ ability to pay their bills. In October 2003, the PA PUC approved Equitable Gas’ revised programs and instructed the various stakeholders to ascertain whether additional funding was necessary to implement the revised programs. Ultimately, consensus was reached to allow the Company to collect an additional $.30 per Mcf to fund the programs. Based on recent billing volumes this would equate to approximately $7.0 million in additional annual revenue. By PA PUC Order of April 1, 2004, the funding mechanism was approved for all residential consumption beginning April 2, 2004, and is expected to remain in place until Equitable Gas seeks authority to change the funding mechanism. This funding mechanism has not had a significant impact on 2004 results because it was approved at the end of the highest volume quarter and during the remainder of 2004 the Company increased spending and focused its collection efforts internally on improving
18
analytical resources to enable the Company to reduce outstanding customer balances. In 2005 and thereafter, it is expected that this mechanism will become a key component in the Company’s efforts to reduce bad debt expense.
On November 30, 2004, Pennsylvania Governor Edward G. Rendell signed into law the Responsible Utility Customer Protection Act (Act 201). Act 201, which became effective on December 14, 2004, established new procedures for utilities regarding collection activities with respect to deposits, payment plans and terminations for residential customers and is intended to help utility companies collect amounts due from customers. As a result of Act 201, the Company is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and to complete customer terminations without approval from the PA PUC. The Company intends to send termination notices to eligible customers in order to reduce delinquent accounts receivable from customers who have the ability to pay. Other regulatory changes mandated by Act 201 will become effective later in 2005 and beyond and will be implemented by the Company as appropriate.
Equitable Gas continues to work with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making. In 2001, Equitable Gas received approval from the PA PUC to implement a performance-based purchased gas cost credit incentive that provides to customers a purchased gas cost credit which is fixed in amount, while enabling Equitable Gas to retain all revenues in excess of the credit through more effective management of upstream interstate pipeline capacity. This performance-based incentive provides an opportunity for Equitable Gas to make short-term releases of unutilized pipeline capacity for a fee and to participate in the bundling of gas supply and pipeline capacity for “off-system” sales. An “off-system” sale involves the purchase and delivery of gas to a customer at mutually agreed-upon points on facilities not owned by the Company. These revenues are recorded within Equitable Utilities’ non-jurisdictional operations. During the third quarter 2002, the PA PUC approved a one-year extension of this program through September 2004. In that same order, the PA PUC approved a second performance-based initiative related to balancing services which is available through September 2005. During the second quarter of 2003, Equitable Gas reached a settlement with all parties to extend its performance-based purchased gas cost credit incentive through September 2005. The settlement also included a new performance-based incentive, which allows Equitable Gas to retain 25% of any revenue generated from a new service designed to increase the recovery of capacity costs from transportation customers. A PA PUC Order approving the settlement was issued in September 2003. This initiative also runs through September 2005.
In the third quarter of 2002, the PA PUC issued an order approving Equitable Gas’ request for a Delinquency Reduction Opportunity Program. The program gives incentives to eligible delinquent customers to make payments exceeding their current bill amount and to receive additional credits from Equitable Gas to reduce the customer’s balance. The program is fully funded through customer contributions and a surcharge in rates.
Equitable Gas submits quarterly purchased gas cost filings to the PA PUC that are subject to quarterly reviews and annual audits and prudency reviews by the PA PUC and its Bureau of Audits. The PA PUC has provided its final prudency review through 2003 in which no material issues were noted. The PA PUC Bureau of Audits commenced a purchased gas cost audit for the 2002-2003 period in the third quarter of 2004. The audit is expected to conclude by the end of the first quarter of 2005.
Interstate Pipeline
The interstate pipeline operations of Equitrans, L.P. (Equitrans) are subject to rate regulation by the Federal Energy Regulatory Commission (FERC). In the second quarter 2002, Equitrans filed with the FERC to merge its assets and operations with the assets and operations of Carnegie Interstate Pipeline Company (Carnegie Pipeline). In April 2003, Equitrans filed a proposed settlement with the FERC related to the application to merge its assets with the assets of the former Carnegie Pipeline operations. The settlement also provided for a deferral to April 2005 of an August 1, 2003 general rate case filing requirement. On July 1, 2003, Equitrans received an order from the FERC approving the merger of Equitrans and Carnegie Pipeline but denying the request for deferral of the requirement to file a rate case by August 1, 2003. In response to the July 1, 2003 order, Equitrans filed for and received an extension of time for its rate case filing deadline from August 1, 2003 until December 1, 2003. Also in response to the July 1, 2003 order, on January 1, 2004, the merger of Equitrans and Carnegie Pipeline was effectuated with Equitrans surviving the merger.
19
Equitrans timely filed its rate case application on December 1, 2003. On December 31, 2003, in accordance with the Natural Gas Act, the FERC issued an order accepting in part and rejecting in part Equitrans’ general rate application. Certain of Equitrans’ proposed tariff sheets were accepted subject to a five-month suspension period, but Equitrans’ requests for revenue relief were denied. The increases were rejected in large part because Equitrans did not provide cost and revenue data for Carnegie Pipeline. Equitrans filed a rehearing request on January 30, 2004, seeking reconsideration of the FERC’s December 31, 2003 order, including the FERC’s order requiring a certificate filing to replenish certain storage base gas volumes.
Equitrans re-filed its rate case application on March 1, 2004, complete with cost and revenue data for the former Carnegie Pipeline operations. Consistent with the Company’s original December 1, 2003 filing, Equitrans’ rate case application addresses several issues including establishing an appropriate return on the Company’s capital investments, the Company’s pension funding levels and accruing for post-retirement benefits other than pensions. The Company’s filed request for rate relief is for an aggregate annual amount of approximately $17.2 million. On March 31, 2004, in accordance with the Natural Gas Act, the FERC issued an order accepting Equitrans’ rate application, suspending its tariff sheets until September 1, 2004, and establishing certain procedural parameters for the case. Equitrans began charging the proposed rates for its core services, subject to refund, on September 1, 2004. The proposed rates for Equitrans’ non-core services were moved into effect, subject to refund, on December 1, 2004, pursuant to Commission orders issued on November 23, 2004 and December 30, 2004. Accordingly, Equitrans has set up a reserve believed by management to be prudent, which will be adjusted upon ultimate resolution of the rate case. The Commission’s November 23, 2004 order also denied Equitrans’ January 30, 2004 rehearing request. The Company is seeking judicial review of this order but intends to address the replenishment of the storage base gas volumes in conjunction with the resolution of its pending rate case. Equitrans will continue to explore and evaluate settlement options throughout the pendency of the proceeding.
Energy Marketing
Equitable Utilities’ energy marketing includes the non-jurisdictional marketing of natural gas at Equitable Gas, marketing and risk management activities at Equitable Energy, LLC (Equitable Energy), and the sale of energy-related products and services by Equitable Homeworks. Equitable Energy provides commodity procurement and delivery, risk management and customer services to energy consumers including large industrial, utility, commercial and institutional end-users. Equitable Energy’s primary focus is to provide products and services in those areas where the Company has a strategic marketing advantage, usually due to geographic coverage and ownership of physical or contractual assets.
Historically, Equitable Utilities’ marketing affiliate purchased and resold a portion of Equitable Supply’s production. Beginning January 1, 2003, these marketing activities have been recorded directly in Equitable Supply. The change did not have a significant impact on the Company as a whole; however, there was a significant reduction in the marketing revenues and purchased natural gas costs for the unregulated marketing activities recorded in Equitable Utilities.
Capital Expenditures
Equitable Utilities forecasts 2005 capital expenditures to be approximately $61 million, a 9% increase over actual capital expenditures of approximately $56 million for 2004. The 2005 capital expenditures are expected to include 2004 capital commitments totaling $7 million. The total 2005 capital expenditures include $48 million for infrastructure improvements, $8 million for technology enhancements and $5 million for new business development. The infrastructure improvements include improvements to existing distribution and transmission lines as well as storage enhancements. The technology expenditures are primarily related to the implementation of an automated meter reading system as well as systems enhancements and integration. The new business capital is planned for distribution extension projects.
During 2004, Equitable Gas implemented a new customer information and billing system for which it incurred $14.3 million of capital expenditures from project inception through December 31, 2004. The system is being depreciated over a fifteen-year period. The new system is expected to help the Company better segment customer information, thereby making it easier for the Company to identify customers eligible for the energy assistance programs and customers for which additional collection efforts are necessary. In 2004, the Company
20
incurred operating costs related to the implementation of the customer information and billing system of $1.9 million and expects to incur additional expense related to ongoing system optimization.
Other
Equitable Gas’ collective bargaining agreement with United Steelworkers of America, Local Union 12050 representing 196 employees expired on April 15, 2003. The union has continued to work under the terms and conditions of the expired contract while negotiating a new contract.
Equitrans’ collective bargaining agreement with Paper, Allied-Industrial, Chemical and Energy Workers Industrial Union Local 5-0843 representing 26 employees expired April 19, 2004. The union has continued to work under the terms and conditions of the expired contract while negotiating a new contract.
Results of Operations
Equitable Utilities
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
Total operating expenses as a % of net operating revenues |
|
55.44 |
% |
55.17 |
% |
56.33 |
% |
|||
|
Capital expenditures (thousands) |
|
$ |
56,274 |
|
$ |
60,414 |
|
$ |
70,188 |
|
|
|
|
|
|
|
|
|
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
Utility revenues (regulated) |
|
$ |
431,348 |
|
$ |
408,110 |
|
$ |
343,847 |
|
|
Marketing revenues |
|
300,513 |
|
205,258 |
|
410,426 |
|
|||
|
Total operating revenues |
|
731,861 |
|
613,368 |
|
754,273 |
|
|||
|
Utility purchased gas costs (regulated) |
|
217,100 |
|
189,998 |
|
131,079 |
|
|||
|
Marketing purchased gas costs |
|
272,056 |
|
178,247 |
|
389,787 |
|
|||
|
Net operating revenues |
|
242,705 |
|
245,123 |
|
233,407 |
|
|||
|
Operating expenses: |
|
|
|
|
|
|
|
|||
|
Operation and maintenance expense |
|
52,481 |
|
51,208 |
|
50,335 |
|
|||
|
Selling, general and administrative expense |
|
56,446 |
|
56,453 |
|
54,249 |
|
|||
|
Depreciation, depletion and amortization |
|
25,629 |
|
27,583 |
|
26,894 |
|
|||
|
Total operating expenses |
|
134,556 |
|
135,244 |
|
131,478 |
|
|||
|
Operating income |
|
$ |
108,149 |
|
$ |
109,879 |
|
$ |
101,929 |
|
Equitable Utilities had operating income of $108.1 million for 2004 compared with $109.9 million for 2003. The decreased results for 2004 are primarily due to warmer weather in the first and fourth quarters of 2004. The Distribution operations also experienced increased insurance and legal costs, operating costs related to the implementation of the customer information system and an increase in Pennsylvania franchise tax. In February 2004, a rate moratorium for West Virginia customers expired. The Distribution operations subsequently returned to normal gas recovery rates which led to a decrease in margins for the full year. These decreases were partially offset by increased gathering revenue at the Distribution and Pipeline operations and higher storage related margins at the Pipeline operations. Bad debt expense decreased from the prior year primarily due to a reduction of a regulatory asset in the current year partially offset by increases associated with the implementation of the customer information system in the current year, which resulted in delays in initiating collection activity. Additionally, there was a reduction in the Distribution operation’s depreciation, depletion and amortization (DD&A) expenses primarily due to an adjustment in the estimated useful life for Equitable Gas’ main lines and services lines resulting from the PA PUC mandated asset service life study.
Capital expenditures decreased $4.1 million to $56.3 million in 2004 from $60.4 million in 2003 due to a decrease in technological enhancement project spending partially offset by increased main line replacement costs and new business development spending.
Operating income for 2003 was $109.9 compared with $101.9 million for 2002. The increase was primarily attributable to colder weather in the first quarter of 2003 offset somewhat by warmer weather in the second and
21
fourth quarters of 2003. Additionally, Energy Marketing experienced an increase in wholesale volumes and margins in both the third and fourth quarters of 2003. These items were offset by an increase in bad debt expense and a decrease in storage related revenues in the Pipeline operations. The Distribution operations also experienced increased operating costs in the first quarter 2003 related to the repair of leaks and increased emergency calls incurred due to the cold weather.
Capital expenditures decreased $9.8 million to $60.4 million in 2003 from $70.2 million in of 2002. The decrease was primarily due to a reduction in new business development spending and mainline replacement.
Distribution Operations
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Heating degree days (30 year average = 5,829) (a) |
|
5,360 |
|
5,695 |
|
5,258 |
|
|||
|
O&M per customer (b) |
|
$ |
294.88 |
|
$ |
290.35 |
|
$ |
265.98 |
|
|
Volumes (MMcf): |
|
|
|
|
|
|
|
|||
|
Residential sales and transportation |
|
25,520 |
|
27,262 |
|
25,646 |
|
|||
|
Commercial and industrial |
|
29,597 |
|
28,784 |
|
29,920 |
|
|||
|
Total throughput |
|
55,117 |
|
56,046 |
|
55,566 |
|
|||
(a) A heating degree day is computed by taking the average temperature on a given day in the operating region and subtracting it from 65 degrees Fahrenheit. Each degree by which the average daily temperature falls below 65 degrees represents one heating degree day.
(b) O&M is defined for this calculation as the sum of operating expenses (total operating expenses excluding depreciation) less other taxes. Other taxes for the years ended December 31, 2004, 2003 and 2002 totaled $3.3 million, $2.4 million and $3.0 million, respectively. In 2004, 2003 and 2002, there were approximately 276,300 customers, 274,500 customers and 275,000 customers, respectively.
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Residential net operating revenues |
|
$ |
104,612 |
|
$ |
109,821 |
|
$ |
105,323 |
|
|
Commercial and industrial net operating revenues |
|
48,563 |
|
50,660 |
|
46,846 |
|
|||
|
Other net operating revenues |
|
5,950 |
|
4,705 |
|
3,924 |
|
|||
|
Total net operating revenues |
|
$ |
159,125 |
|
$ |
165,186 |
|
$ |
156,093 |
|
|
Operating expenses (total operating expenses excluding depreciation, depletion and amortization) |
|
84,774 |
|
82,068 |
|
76,139 |
|
|||
|
Depreciation, depletion and amortization |
|
17,474 |
|
20,025 |
|
19,933 |
|
|||
|
Operating income |
|
$ |
56,877 |
|
$ |
63,093 |
|
$ |
60,021 |
|
Net operating revenues for 2004 were $159.1 million compared to $165.2 million in 2003. Heating degree days were 5,360 in 2004, which is 6% warmer than the 5,695 degree days in 2003. The majority of the decrease in net operating revenues is attributable to warmer weather in 2004 versus 2003 that had a negative impact of $4.6 million and a $0.5 million favorable 2003 adjustment as a result of a routine PA PUC audit of Equitable’s gas cost. Commercial and industrial net operating revenues were down $1.2 million primarily due to the transfer of responsibility for certain commodity margins to Energy Marketing related to the agency program whereby Energy Marketing procures the supply and manages any associated market risk for customers. The transportation responsibility related to these customers remains with the Distribution operations. The related commercial and
22
industrial volumes increased primarily due to low margin industrial usage and, therefore, had minimal impact on net operating revenues. Additionally, in February 2004, a rate moratorium for West Virginia customers expired. The Distribution operations subsequently returned to normal gas recovery rates. This expiration led to a $0.9 million decrease in margins for the full year. These decreases were partially offset by $1.9 million of gathering revenue related to assets transferred from the Pipeline operations during the first quarter of 2004. Of the $1.9 million, $0.5 million related directly to the assets transferred from the Pipeline operations for the full year while the remaining $1.4 million was due to the Distribution operations’ ability to increase revenue from the transferred assets as a result of improvements to, and further utilization of, existing Distribution gathering facilities during 2004.
Operating expenses, excluding DD&A, increased by $2.7 million to $84.8 million in 2004 from $82.1 million in 2003. The increase in operating expenses was due to $1.7 million of higher insurance and legal costs, increased operating costs of $1.1 million related to the implementation of the Distribution operation’s customer information system (net of decreased mainframe costs of $0.8 million related to the previous customer information system) and an increase in PA franchise tax of $0.9 million. Additionally, as a result of the flooding which occurred in September 2004 due to Hurricane Ivan, $0.7 million of expense was incurred primarily related to increased overtime and contractor costs. These increases were partially offset by a reduction in cold weather-related maintenance costs and on-going cost reduction initiatives. Bad debt expense decreased by $1.7 million from the prior year due to a reduction of a regulatory asset of $7.5 million in 2004, partially offset by increases of $5.8 million mainly related to delays in initiating collection activity due to the implementation of the customer information system in 2004 as well as increased gas rates in the current year. The reduction in the regulatory asset was due to Equitable Gas having higher than anticipated recoveries for the Delinquency Reduction Opportunity Program through payment and rates. DD&A expense decreased by $2.5 million from 2003 primarily due to an adjustment in the estimated useful life for Equitable Gas’ main lines and services lines resulting from the PA PUC mandated asset service life study. The adjustment made in the fourth quarter 2004 for the full year resulted in a decrease in DD&A expenses of $3.5 million. This decrease was partially offset by an increase of $1.0 million related mainly to increased capital in 2004, of which approximately $0.5 million was related to the implementation of the customer information system.
Net operating revenues for 2003 were $165.2 million compared to $156.1 million in 2002. Heating degree days were 5,695 in 2003, which was 8% cooler than the 5,258 degree days in 2002. The colder weather had a positive year-over-year impact on net operating revenues of approximately $6.3 million. The additional increase in commercial and industrial net operating revenues of $1.7 million was primarily due to increased delivery margins during the first, second, and fourth quarters of 2003, despite the 4% decrease in related volumes. The related volumes decreased primarily due to low margin industrial usage and, therefore, had minimal impact on net operating revenues.
Operating expenses, excluding DD&A, increased by $5.9 million in 2003 from $76.1 million in 2002. The primary cause for the increase in expenses was an increase of $4.3 million in bad debt expense, which was recorded at approximately 5% of residential revenues, combined with higher cold-weather related maintenance costs from the first quarter 2003 for the repair of leaks and increased emergency calls. These increases were offset by on-going cost reduction initiatives.
Pipeline Operations
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Transportation throughput (Bbtu) |
|
68,929 |
|
72,988 |
|
70,197 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net operating revenues |
|
$ |
55,123 |
|
$ |
52,926 |
|
$ |
56,675 |
|
|
Operating expenses (Total operating expenses excluding depreciation, depreciation and amortization) |
|
22,482 |
|
23,237 |
|
24,744 |
|
|||
|
Depreciation, depletion and amortization |
|
7,985 |
|
7,274 |
|
6,553 |
|
|||
|
Operating income |
|
$ |
24,656 |
|
$ |
22,415 |
|
$ |
25,378 |
|
23
Total transportation throughput decreased 4.1 million MMbtu, or 6% in 2004 from the prior year due primarily to warmer weather during the first and fourth quarters of 2004. This decrease in volumes was partially offset by increased firm transportation to a third party customer. Because firm transportation contracts, which contain fixed monthly fees regardless of the volumes transported, constitute most of the Pipeline operations’ business, the decreased throughput did not negatively impact net operating revenues.
Net operating revenues from pipeline operations in 2004 increased to $55.1 million from $52.9 million in 2003. The increase in net operating revenues was a result of increased storage margins of $1.5 million in the fourth quarter 2004. Additionally, gathering revenues increased $1.2 million due to increased volumes combined with a rate increase in 2004 compared to 2003. This increase was partially offset by a $0.5 million decrease related to the transfer of gathering assets to the Distribution operations in the first quarter 2004.
Operating expenses, excluding DD&A, decreased by $0.7 million to $22.5 million in 2004. The decrease was primarily due to a reduction in pipeline maintenance charges combined with ongoing cost reduction initiatives. Partially offsetting this decrease, DD&A expense increased by $0.7 million mainly due to increased capital primarily for pipeline replacement and storage enhancement projects.
Net operating revenues from pipeline operations in 2003 decreased to $52.9 million from $56.7 million in 2002. The change in net operating revenues was due almost entirely to a decrease in storage related revenue as a result of firm customer delivery demands in the first quarter of 2003 from colder weather and higher gas prices. In addition, the high gas prices and lower demand in the second, third and fourth quarters of 2003 resulted in the inability to take advantage of commercial opportunities that typically exist.
Operating expenses, excluding DD&A, decreased by $1.5 million from $24.7 million in 2002 to $23.2 million in 2003. The decrease was primarily due to planned maintenance charges related to a pipeline maintenance program recognized in the third quarter of 2002 combined with ongoing cost reduction initiatives.
Energy Marketing
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Total throughput (Bbtu) |
|
52,366 |
|
40,430 |
|
169,942 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Net operating revenues |
|
$ |
28,457 |
|
$ |
27,011 |
|
$ |
20,639 |
|
|
Operating expenses (Total operating expenses excluding depreciation, depletion and amortization) |
|
1,671 |
|
2,356 |
|
3,701 |
|
|||
|
Depreciation, depletion and amortization |
|
170 |
|
284 |
|
408 |
|
|||
|
Operating income |
|
$ |
26,616 |
|
$ |
24,371 |
|
$ |
16,530 |
|
Net operating revenues increased approximately $1.5 million in the current year, from $27.0 million in 2003 to $28.5 million in 2004. This increase was primarily the result of higher commercial and industrial margins, which were previously recorded by the Distribution operations. The increase in volumes over the prior year is primarily attributable to higher off-system volumes and increased commercial and industrial volumes.
Operating expenses, excluding DD&A, decreased $0.7 million, or 29%, from $2.4 million in 2003 to $1.7 million in 2004. This decrease is mainly the result of reduced marketing activities related to home gas products and services, partially offset by higher legal costs.
Net operating revenues in 2003 increased to $27.0 million from $20.6 million in 2002, or 31%, as a result of increased sales for resale off the Equitable Utilities’ systems, increased unit marketing margins, and the continued focus on high margin sales through storage optimization and asset management. The Equitable Supply segment assumed the direct marketing of a substantial portion of its operating volumes at the beginning of 2003, which had
24
previously been marketed by Energy Marketing. These volumes, totaling approximately 138,000 billion British thermal units (Bbtu) in 2003, had been marketed by Energy Marketing at very low margins. Although the assumption of these volumes by Equitable Supply did not have a significant impact on Energy Marketing’s net operating revenues for the year-ended December 31, 2003, it was the primary reason for the significant increase in the unit marketing margins during that same period.
Operating expenses, excluding DD&A, decreased by $1.3 million from 2002 to 2003 primarily due to the recovery of a bankrupt customer’s balance in 2003 that was reserved for in 2002 and a reduction in bad debt expense, as well as continued cost reduction initiatives associated with the Company’s decision to de-emphasize low margin trading-oriented activities.
Equitable Supply
Equitable Supply consists of two activities, production and gathering, with operations in the Appalachian Basin region of the United States. Equitable Production develops, produces and sells natural gas (and minor amounts of associated crude oil and natural gas liquids). Equitable Gathering engages in natural gas gathering and the processing and sale of natural gas liquids.
Equitable Supply completed several transactions in 2004, 2003 and 2002, which affect the comparability of the financial data among those years.
Prepaid Natural Gas Sales
In 2000, the Company entered into two prepaid natural gas sales contracts pursuant to which the Company was required to sell and deliver 52.7 Bcf of natural gas during the term of the contracts. The first contract was for five years with net proceeds of $104.0 million. The second contract was for three years with net proceeds of $104.8 million and was completed at the end of 2003. These contracts were recorded as prepaid forward sales, and the related income was recognized as deliveries occurred.
In June 2004, the Company continued to evaluate its capital structure as a result of the anticipated increase in liquidity expected from the Westport/Kerr-McGee merger. Based on this evaluation, the Company amended the remaining prepaid natural gas contract, which had been viewed as debt by the rating agencies. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company’s obligation to deliver a fixed quantity of gas at a fixed price has not changed but the amendment has the effect of increasing the realized sales price for the delivery of gas for the remaining term of the contract. As such, the Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the Consolidated Balance Sheets and recorded a loss in the second quarter of 2004 of $5.5 million in other income, net in the Statements of Consolidated Income reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue. Prospectively, through the term of the remaining contract (December 2005), the Company will deliver the required quantity of gas at an effective price of $4.79 per Mcf rather than $3.99 per Mcf as originally stated in the contract. Income will continue to be recognized upon delivery of the gas.
Sales of Gas Properties
Occasionally, the Company enters into a sale of gas properties in order to reduce its exposure to commodity volatility, to reduce counter-party risk, to eliminate production risk, and to raise capital, while providing the Company market-based fees associated with the gathering, marketing, and operation of these producing properties.
In June 2000, Equitable sold properties with 66.0 Bcfe of reserves qualifying for the nonconventional fuels tax credit to a partnership, Eastern Seven Partners, L.P. (ESP), for proceeds of approximately $122.2 million and a retained interest in the partnership. This sale of gas properties reduced the natural gas production revenue and reserves reported in subsequent years. The Company retained an interest in the partnership that is recorded as equity in nonconsolidated investments on the Consolidated Balance Sheets under the equity method of accounting. Under the terms of the transaction, the Company’s equity interest will increase under certain circumstances upon achieving certain production goals. The Company separately negotiated arms-length, market-based rates for gathering, marketing and operating fees with the partnership in order to deliver the partnership’s natural gas to the market. The underlying contracts associated with these fees are subject to annual renewal after an initial term.
25
In December 2000, Equitable sold properties with 133.3 Bcfe of reserves to a trust, Appalachian Natural Gas Trust (ANGT), for proceeds of approximately $255.8 million and a retained interest in the trust. This sale of gas properties reduced the natural gas production revenue and reserves reported in subsequent years. The Company retained an interest in the trust, which is recorded as equity in nonconsolidated investments on the Consolidated Balance Sheets under the equity method of accounting. Under the terms of the transaction the Company’s equity interest will increase under certain circumstances upon achieving certain production goals. The Company separately negotiated arms-length, market-based rates for gathering, marketing and operating fees with the trust in order to deliver the trust’s natural gas to the market. The underlying contracts associated with these fees are subject to annual renewal. As the operator of the gas properties and as a result of a separate agreement, the Company receives a market-based fee for providing a restricted line of credit to the trust that is limited by the fair market value of the trust’s remaining reserves.
Below is a table that details information associated with the Company’s sales of gas properties in 2000 to ESP and ANGT as of December 31, 2004, 2003 and 2002.
|
Sales of |
|
Reserves |
|
Volumes Produced (Bcfe) |
|
Revenue Recognized from Fees |
|
|||||||||||
|
|
|
|
(Thousands) |
|
||||||||||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
2004 |
|
2003 |
|
2002 |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
|
ESP |
|
66.0 |
|
8.9 |
|
9.0 |
|
9.6 |
|
$ |
9,266 |
|
$ |
8,619 |
|
$ |
8,522 |
|
|
ANGT |
|
133.3 |
|
13.1 |
|
13.6 |
|
14.2 |
|
$ |
15,598 |
|
$ |
15,053 |
|
$ |
15,442 |
|
In February 2003, the Company sold approximately 500 of its low-producing wells, within two of its non-strategic districts, in two separate transactions. The sales resulted in a decrease of approximately 13 Bcf of net reserves for proceeds of approximately $6.6 million. The wells produced an aggregate of approximately 1.0 Bcf in 2002. The Company did not recognize a gain or a loss as a result of this disposition.
In January 2005, Equitable purchased the 99% limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves. Equitable expects to sell some non-core producing properties during the first half of 2005. The net result of the purchase and sale is expected to increase the sales volume at Equitable Supply to 73 Bcfe in 2005. The expected increased revenues will be partially offset by lower other revenues from fees formerly paid by ESP for marketing and operating services.
Appalachian Basin Partners, LP
In November 1995, the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit to a partnership, Appalachian Basin Partners, LP (ABP). The Company recorded the proceeds as deferred revenue, which was recognized as production occurred. The Company retained a partnership interest in the properties that increased substantially at the end of 2001 based on the attainment of a performance target. The Company consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest.
As a result of the Company’s increased partnership interest in ABP in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit attributable to ABP. This resulted in a reduction of the Company’s effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002 and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future.
In February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million. The 31% limited partnership interest represented approximately 60.2 Bcf of reserves. As a result, effective February 1, 2003, the Company no longer recognizes minority interest expense associated with ABP, which totaled $0.9 million and $7.1 million for the years ended December 31, 2003 and 2002, respectively.
26
Capital Expenditures
Equitable Supply forecasts its 2005 capital expenditures to be approximately $219 million which excludes the $57.5 million purchase of ESP in January 2005. The forecast includes $133 million for the development of Appalachian holdings and $86 million for improvements and extensions to gathering system pipelines. The $133 million targeted to the development of Appalachian holdings represents a $42 million increase in capital expenditures from 2004 to 2005 attributable to an expanded drilling program in Virginia, West Virginia and Kentucky. The evaluation of new development locations, market forecasts and price trends for natural gas and oil will continue to be the principal factors for the economic justification of drilling and gathering system investments.
Other
Equitable Supply implemented a significant change to its business model in late 2004. Previously, Equitable Supply followed an operating cost minimization strategy combined with a moderate drilling program. The Company’s new strategy focuses on profit maximization, rather than cost minimization, as an objective. Equitable Supply’s previous strategy was based on low price assumptions. To assume low prices, however, in spite of current market conditions, limits opportunities. The margin leverage from realizable gas prices substantially outweighs the modest increase in unit cost structure necessary to utilize this strategy. In the second quarter of 2004, the Company reduced the expected number of wells to be drilled in 2004 from 340 to 320, consistent with the increased focus on infrastructure this year. This change was intended to accelerate sales from existing wells, to reduce the Company’s long-term requirement for maintenance capital with respect to these wells, and to provide a platform for higher drilling levels prospectively. With the significant and sustained increase in NYMEX natural gas prices during the past several months, the Company re-evaluated its growth strategy. By providing for a stable base infrastructure for the current natural gas wells, the Company can benefit from the higher gas prices by obtaining accelerated volumes from the current wells and by increasing the number of wells it intends to drill in 2005 and beyond. At a NYMEX price of $6.00, in addition to the 1,441 net proved undeveloped drilling locations, the Company believes that it has available on acreage it controls, at least 7,000 additional net drilling locations on unproved properties. The execution of this new model will be challenging and will result in higher operating expense, but the Company is committed to improving outcomes through actions such as: (1) significantly increasing the Company’s focus on well performance by lowering bottom-hole pressure; (2) accelerating implementation and installation of compressor stations and facilities to lower surface pressure; (3) reducing internal and external curtailments of gas sales; (4) reducing “lost” gas to the minimum level that can be justified economically and not accepting “unaccounted for” gas; and (5) increasing accountability, ownership and attention to detail in the field and engineering areas.
Equitable Supply
Operational and Financial Data
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
Total sales volumes (MMcfe) |
|
67,731 |
|
64,306 |
|
61,719 |
|
|||
|
Capital expenditures (thousands) (a) |
|
$ |
141,661 |
|
$ |
204,527 |
|
$ |
147,461 |
|
(a) 2003 capital expenditures include the purchase of the remaining 31% limited partnership interest in ABP ($44.2 million) which was separately approved by the Board of Directors of the Company in addition to the total amount originally authorized for the 2003 capital budget program.
27
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
Production revenues |
|
$ |
315,986 |
|
$ |
262,607 |
|
$ |
225,713 |
|
|
Gathering revenues |
|
74,442 |
|
69,827 |
|
63,279 |
|
|||
|
Total net operating revenues |
|
390,428 |
|
332,434 |
|
288,992 |
|
|||
|
Operating expenses: |
|
|
|
|
|
|
|
|||
|
Lease operating expenses, excluding severance taxes |
|
26,080 |
|
22,278 |
|
18,988 |
|
|||
|
Severance tax |
|
17,194 |
|
13,409 |
|
8,123 |
|
|||
|
Gathering and compression (operation and maintenance) |
|
35,494 |
|
25,110 |
|
23,095 |
|
|||
|
Selling, general and administrative (SG&A) |
|
28,455 |
|
27,094 |
|
26,873 |
|
|||
|
Depreciation, depletion and amortization (DD&A) |
|
55,836 |
|
48,748 |
|
40,711 |
|
|||
|
Total operating expenses |
|
163,059 |
|
136,639 |
|
117,790 |
|
|||
|
Operating income |
|
$ |
227,369 |
|
$ |
195,795 |
|
$ |
171,202 |
|
|
Other income, net |
|
$ |
576 |
|
$ |
— |
|
$ |
— |
|
|
Equity earnings from nonconsolidated investments |
|
$ |
688 |
|
$ |
431 |
|
$ |
282 |
|
|
Minority interest |
|
$ |
— |
|
$ |
(871 |
) |
$ |
(7,103 |
) |
Equitable Supply’s operating income for 2004 totaled $227.4 million, 16% higher than the $195.8 million earned in 2003. The segment’s 2004 net operating revenues were $390.4 million, 17% higher than the 2003 net operating revenues of $332.4 million. The increases in Equitable Supply’s operating income and net operating revenues were primarily the result of a 14% higher average well-head sales price, a 5% increase in sales volumes, and a 7% increase in gathering revenues.
Equitable Supply’s average well-head sales price realized on produced volumes for 2004 was $4.46 per Mcfe compared to $3.91 per Mcfe for 2003. The $0.55 per Mcfe increase in the average well-head sales price was attributable to higher gas commodity prices, increased volumes at higher hedged prices and increased basis over the same period in 2003. The 5% increase in sales volumes was primarily the result of new wells drilled in 2003 and 2004 and production enhancements partially offset by the normal production decline in the Company’s wells. The 7% increase in revenues from gathering fees was attributable to a 5% increase in the average gathering rate and higher Equitable Production sales volumes, partially offset by third party customer volume shut-ins.
Total operating expenses were $163.1 million for 2004 compared to $136.6 million for 2003, an increase of 19%. The increase in gathering and compression costs was primarily attributable to an increase in compressor station operation and repair costs, field labor and related employments costs, field line maintenance costs and compressor electricity charges. The increase in DD&A resulted from a $0.05 per Mcfe increase in the unit depletion rate and increased production volumes. The increase in severance taxes (a tax imposed on the value of gas extracted) was primarily attributable to higher gas commodity prices and sales volumes. The increase in lease operating expenses was primarily the result of a charge for environmental site assessments and increased property taxes and liability insurance premiums. The increase in SG&A was due to increased franchise taxes in 2004.
Other income, net was the result of a $6.1 million settlement received from a previously disputed insurance coverage claim, offset by a $5.5 million expense related to the Company’s settlement of its prepaid forward contract in the second quarter of 2004.
Capital expenditures decreased from $204.5 million in 2003 to $141.7 million in 2004 primarily as a result of a decrease in the level of development drilling in the Appalachian holdings to allow Equitable Supply to concentrate on its core assets and insure a proper level of return on all new projects. The capital expenditures in 2004 and 2003 included $91.5 million and $126.0 million, respectively, for the development of Appalachian holdings and $50.2 million and $34.3 million, respectively, for gathering system improvements and extensions.
Equitable Supply had operating income of $195.8 million for 2003, compared with $171.2 million in 2002. The increase was primarily due to a $0.44 per Mcfe increase in average well-head sales price, a 4% increase in sales volumes and a 10% increase in revenues from gathering partially offset by an increase in operating expenses. The net increase in operating expenses was primarily due to an increase in lease operating expenses, severance taxes, higher DD&A resulting from a $0.09 per Mcfe increase in the unit depletion rate and increased production volumes,
28
and higher gathering and compression expenses mainly attributable to an increase in gathering fees paid to third parties. The increase in severance taxes was primarily attributable to higher gas commodity prices. The increase in lease operating expenses was primarily the result of an increase in road maintenance and other repair costs due to severe weather and flooding in 2003, and increases in property taxes and liability insurance premiums. SG&A costs remained consistent from 2002 to 2003 as a result of a reduction in legal claims and reserves being offset by a $2.0 million loss incurred during 2003 on the early termination of an uneconomic sales contract.
Capital expenditures increased from $147.5 million in 2002 to $204.5 million in 2003 primarily as a result of an increase in the level of development drilling in the Appalachian holdings and the purchase of the remaining limited partnership interest in ABP for $44.2 million. The capital expenditures in 2003 and 2002 included $126.0 million and $114.4 million, respectively, for the development of Appalachian holdings and $34.3 million and $33.1 million, respectively, for gathering system improvements and extensions.
Equitable Production
Operational and Financial Data
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
Total sales volumes (MMcfe) (a) |
|
67,731 |
|
64,306 |
|
61,719 |
|
|||
|
Average (well-head) sales price ($/Mcfe) |
|
$ |
4.46 |
|
$ |
3.91 |
|
$ |
3.47 |
|
|
|
|
|
|
|
|
|
|
|||
|
Company usage, line loss (MMcfe) (a) |
|
5,090 |
|
5,501 |
|
6,216 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Natural gas inventory usage, net (MMcfe) |
|
(61 |
) |
112 |
|
— |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Natural gas and oil production (MMcfe) (b) |
|
72,760 |
|
69,919 |
|
67,935 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Operated volumes – third parties (MMcfe) (c) |
|
21,865 |
|
22,619 |
|
23,858 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Lease operating expense (LOE), excluding severance tax ($/Mcfe) |
|
$ |
0.36 |
|
$ |
0.32 |
|
$ |
0.28 |
|
|
Severance tax ($/Mcfe) |
|
$ |
0.24 |
|
$ |
0.19 |
|
$ |
0.12 |
|
|
Production depletion ($/Mcfe) |
|
$ |
0.54 |
|
$ |
0.49 |
|
$ |
0.40 |
|
|
|
|
|
|
|
|
|
|
|||
|
Depreciation, depletion and amortization (in thousands): |
|
|
|
|
|
|
|
|||
|
Production depletion |
|
$ |
39,100 |
|
$ |
33,911 |
|
$ |
26,970 |
|
|
Other depreciation, depletion and amortization |
|
2,175 |
|
2,063 |
|
1,417 |
|
|||
|
Total depreciation, depletion and amortization |
|
$ |
41,275 |
|
$ |
35,974 |
|
$ |
28,387 |
|
(a) Effective January 1, 2003, the Company adjusted its method for using a natural gas equivalents conversion factor to convert gallons of liquid hydrocarbon sales to equivalent volumes of natural gas sales. This change results in an additional 0.3 Bcfe natural gas sales volume and a corresponding reduction to reported Company usage and line loss for the year ended December 31, 2003. The decrease in Company usage and line loss for the year ended December 31, 2004 as compared to year ended December 31, 2003 was primarily due to improved meter calibration on the Company’s wells.
(b) Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage, line loss, and natural gas inventory.
(c) Includes volumes in which interests were sold but which the Company still operates for third parties for a fee. See the ESP and ANGT table in the “Sale of Gas Properties” section for additional information.
29
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
Production revenues |
|
$ |
302,287 |
|
$ |
251,658 |
|
$ |
214,225 |
|
|
Other revenue |
|
13,699 |
|
10,949 |
|
11,488 |
|
|||
|
Total production revenues |
|
315,986 |
|
262,607 |
|
225,713 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Operating expenses: |
|
|
|
|
|
|
|
|||
|
Lease operating expense, excluding severance taxes |
|
26,080 |
|
22,278 |
|
18,988 |
|
|||
|
Severance tax |
|
17,194 |
|
13,409 |
|
8,123 |
|
|||
|
Selling, general and administrative (SG&A) |
|
18,780 |
|
18,562 |
|
18,926 |
|
|||
|
Depreciation, depletion and amortization (DD&A) |
|
41,275 |
|
35,974 |
|
28,387 |
|
|||
|
Total operating expenses |
|
103,329 |
|
90,223 |
|
74,424 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Operating income |
|
$ |
212,657 |
|
$ |
172,384 |
|
$ |
151,289 |
|
|
|
|
|
|
|
|
|
|
|||
|
Other income, net |
|
$ |
576 |
|
$ |
— |
|
$ |
— |
|
|
Equity earnings from nonconsolidated investments |
|
$ |
688 |
|
$ |
431 |
|
$ |
282 |
|
|
Minority interest |
|
$ |
— |
|
$ |
(871 |
) |
$ |
(7,103 |
) |
Equitable Production’s total production revenues, which are derived primarily from the sale of produced natural gas, increased $53.4 million from 2003 to 2004. The increase was primarily the result of a 14% increase in the average well-head sales price of $4.46 per Mcfe compared to $3.91 per Mcfe in the prior year and increased sales volumes of 3.4 Bcfe. The increase in sales volumes was the result of new wells drilled in 2003 and 2004, reduction in the average line pressure in the gathering system by 13%, and production enhancements, partially offset by the normal production decline in the Company’s wells.
Production operating revenues were also positively impacted in 2004 by the recognition of a gain of $2.7 million that resulted from the renegotiation of a processing agreement. The Company received approximately $3.3 million from a contract buydown fee related to the renegotiation of a pre-existing liquids processing agreement from a make-whole arrangement to a processing fee arrangement. Under the terms of the new agreement, Equitable will have increased exposure to liquids prices and will pay a fee on volumes processed. This $3.3 million was partially offset by a $0.6 million write down of certain plant assets that no longer have future economic value under the new agreement.
Operating expenses increased $13.1 million or 15% over the prior year from $90.2 million to $103.3 million. This increase was primarily due to a $5.3 million increase in DD&A costs, a $3.8 million increase in severance taxes attributable to higher natural gas prices and increased sales volume, and a $3.8 million increase in lease operating expenses. The increase in DD&A was primarily due to a $0.05 per Mcfe increase in the unit depletion rate and increased production volumes. The $0.05 per Mcfe increase in the unit depletion rate was the result of the net development capital additions in 2003 on a relatively consistent proved reserve base. The increase in lease operating expenses was due to a charge to earnings for environmental site assessments performed in accordance with the Company’s amended Spill Prevention, Control and Countermeasure (SPCC) compliance plan, and increased property taxes and liability insurance premiums. In general, the higher cost structure reflects the change in the strategy from cost minimization previously addressed.
Other income, net was the result of a $6.1 million settlement received from a disputed insurance coverage claim, offset by a $5.5 million expense related to the Company’s amendment of its prepaid forward contract in the second quarter of 2004.
Total production revenues increased $36.9 million from 2002 to 2003. The increase was primarily the result of a $37.4 million increase in production revenues from 2002 due to a higher average well-head sales price of $3.91 per Mcfe compared to $3.47 per Mcfe in the prior year and increased sales volumes of 2.6 Bcfe.
30
Operating expenses for the year ended December 31, 2003 increased 21% as compared to the same period in 2002. This increase was primarily due to a $7.6 million increase in DD&A costs, $5.3 million in higher severance taxes attributable to higher natural gas prices, and a $3.3 million increase in lease operating expenses.
Equitable Gathering
Operational and Financial Data
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Gathered volumes (MMcfe) |
|
127,339 |
|
126,674 |
|
123,581 |
|
|||
|
Average gathering fee ($/Mcfe) (a) |
|
$ |
0.58 |
|
$ |
0.55 |
|
$ |
0.51 |
|
|
Gathering and compression expense ($/Mcfe) |
|
$ |
0.28 |
|
$ |
0.20 |
|
$ |
0.19 |
|
|
Gathering and compression depreciation ($/Mcfe) |
|
$ |
0.11 |
|
$ |
0.09 |
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
|
|||
|
Depreciation, depletion and amortization (in thousands): |
|
|
|
|
|
|
|
|||
|
Gathering and compression depreciation |
|
$ |
13,441 |
|
$ |
11,711 |
|
$ |
11,594 |
|
|
Other depreciation, depletion and amortization |
|
1,120 |
|
1,063 |
|
730 |
|
|||
|
Total depreciation, depletion and amortization |
|
$ |
14,561 |
|
$ |
12,774 |
|
$ |
12,324 |
|
(a) Revenues associated with the use of pipelines and other equipment to collect, process and deliver natural gas from the field where it is produced, to the trunk or main transmission line. Many contracts are for a blended gas commodity and gathering price, in which case the Company utilizes standard measures in order to split the price into its two components.
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
Gathering revenues |
|
$ |
74,442 |
|
$ |
69,827 |
|
$ |
63,279 |
|
|
|
|
|
|
|
|
|
|
|||
|
Operating expenses: |
|
|
|
|
|
|
|
|||
|
Gathering and compression expense |
|
35,494 |
|
25,110 |
|
23,095 |
|
|||
|
Selling, general and administrative (SG&A) |
|
9,675 |
|
8,532 |
|
7,947 |
|
|||
|
Depreciation, depletion and amortization |
|
14,561 |
|
12,774 |
|
12,324 |
|
|||
|
Total operating expenses |
|
59,730 |
|
46,416 |
|
43,366 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Operating income |
|
$ |
14,712 |
|
$ |
23,411 |
|
$ |
19,913 |
|
Equitable Gathering’s total operating revenues increased $4.6 million or 7% from $69.8 million in 2003 to $74.4 million in 2004. The 7% increase in total operating revenues was primarily attributable to a 6% rise in the average gathering fee and a 0.7 Bcf increase in gathered volumes. The increase in gathered volumes was the result of higher Equitable Production sales volumes, partially offset by third party customer volume shut-ins caused by extended maintenance projects on interstate pipelines.
Total operating expenses increased $13.3 million or 29% from $46.4 million in 2003 to $59.7 million in 2004. The increase resulted from a $10.4 million increase in gathering and compression costs, a $1.8 million increase in depreciation relating to capital expenditures for gathering system improvements and extensions, and a $1.1 million increase in SG&A expense. The increase in gathering and compression costs was primarily attributable to an increase in compressor station operation and repair costs, field labor and related employment costs, field line maintenance costs and compressor electricity charges resulting from newly installed electric compressors. The additional compression costs resulted from a 24% increase in horsepower (hp) to approximately 112,000 hp in 2004 from approximately 90,000 hp in 2003. The increase in field labor was due to an increase in headcount related to Equitable Gathering’s current strategy to spend more time and resources to aggressively tend to the improvement of the base infrastructure. Actions taken by Equitable Gathering to support this strategy, such as the installation of compressor stations and facilities to reduce surface pressure and efforts related to reducing the internal curtailment
31
of gas sales, have increased compression and field line maintenance costs in 2004. Equitable Gathering will pursue recovery of the increased cost to provide gathering services through the rates it charges to its customers. The increase in SG&A costs was primarily attributable to an increase in franchise taxes due to an increase in the tax base.
Equitable Gathering’s total operating revenues increased $6.5 million or 10% from $63.3 million in 2002 to $69.8 million in 2003. The increase was primarily attributable to a 8% rise in the average gathering fee billed to equity and third party customers in addition to a 3.1 Bcfe increase in gathered volumes resulting from higher Equitable Production volumes and new third party customers in southern West Virginia.
Total operating expenses increased to $46.4 million in 2003 from $43.4 million in 2002, a 7% increase year over year primarily due to higher third party gathering costs, other gathering and compression expense increases and higher depreciation relating to capital expenditures for gathering system improvements and extensions.
NORESCO
NORESCO provides an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency. The segment’s activities comprise performance contracting, energy efficiency programs, combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation. NORESCO’s customers include governmental, military, institutional, commercial and industrial end-users.
On September 30, 2003, the enabling legislation for the performance contracting work that NORESCO performs for the federal government under the Department of Energy contracts lapsed. On October 28, 2004, the President signed legislation extending the contracting period for performance contracting at federal government facilities through October 2006.
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
OPERATIONAL DATA |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Revenue backlog at December 31 (thousands) |
|
$ |
83,526 |
|
$ |
134,195 |
|
$ |
118,224 |
|
|
Gross profit margin |
|
26.9 |
% |
24.0 |
% |
21.2 |
% |
|||
|
SG&A as a% of revenue |
|
16.0 |
% |
13.3 |
% |
12.4 |
% |
|||
|
|
|
|
|
|
|
|
|
|||
|
Capital expenditures (thousands) |
|
$ |
538 |
|
$ |
307 |
|
$ |
698 |
|
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
FINANCIAL DATA (Thousands) |
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Energy service contract revenues |
|
$ |
146,426 |
|
$ |
170,703 |
|
$ |
190,107 |
|
|
Energy service contract costs |
|
107,090 |
|
129,689 |
|
149,801 |
|
|||
|
Net operating revenue (gross profit margin) |
|
39,336 |
|
41,014 |
|
40,306 |
|
|||
|
Operating expenses: |
|
|
|
|
|
|
|
|||
|
Selling, general and administrative |
|
23,403 |
|
22,667 |
|
23,521 |
|
|||
|
Impairment of long lived assets |
|
— |
|
— |
|
5,320 |
|
|||
|
Depreciation, depletion and amortization |
|
987 |
|
1,416 |
|
1,618 |
|
|||
|
Total operating expenses |
|
24,390 |
|
24,083 |
|
30,459 |
|
|||
|
Operating income |
|
$ |
14,946 |
|
$ |
16,931 |
|
$ |
9,847 |
|
|
Equity earnings of nonconsolidated investments |
|
$ |
1,152 |
|
$ |
2,470 |
|
$ |
4,699 |
|
|
International investments, primarily impairment |
|
$ |
(39,590 |
) |
$ |
(11,059 |
) |
$ |
— |
|
|
Minority interest |
|
$ |
(976 |
) |
$ |
(542 |
) |
$ |
— |
|
32
Revenues decreased to $146.4 million in 2004 from $170.7 million in 2003, a decrease of $24.3 million, or 14%. This decrease was due primarily to decreased construction activity mainly related to reduced sales during the year. Gross profit margin decreased to $39.3 million compared to $41.0 million in the same period last year. Gross profit margin as a percentage of revenue increased to 27% in 2004 from 24% in 2003 reflecting a change in the mix of projects constructed during the year.
Revenue backlog decreased to $83.5 million at year-end 2004 from $134.2 million at year-end 2003. This decrease in backlog was primarily due to the inability to contract with the federal government between September 30, 2003 and October 28, 2004.
Total operating expenses increased by $0.3 million from $24.1 million in 2003 to $24.4 million in 2004. This increase was primarily due to an increase in SG&A expenses which includes expenses related to the litigation regarding EAL/ERI Cogeneration Partners LP (Jamaica). Included in SG&A expenses in 2003 was $0.8 million related to the consolidation of the energy infrastructure and performance contracting groups. Excluding these isolated items, SG&A expenses were flat compared to prior year.
During the second quarter of 2004, several negative circumstances caused the Company to evaluate its international investments for additional impairments and to accelerate its plans to exit the international generation business. See “Equity in Nonconsolidated Investments” in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information regarding the $39.6 million impairment charge recorded in 2004. Equity earnings of nonconsolidated investments of $1.2 million in 2004 and $2.5 million in 2003 reflects NORESCO’s share of the earnings from its equity investments in power plant assets. The decrease in earnings from 2003 was primarily due to the Company’s strategy to exit the international generation business.
The Company began recording minority interest expense upon the consolidation of Hunterdon Cogeneration LP (Hunterdon) in June 2003. The increase in minority interest expense from $0.5 million in 2003 to $1.0 million in 2004 was due to the consolidation of Hunterdon for six months in 2003 versus a full calendar year in 2004.
Revenues decreased to $170.7 million in 2003 from $190.1 million in 2002, a decrease of $19.4 million, or 10%. This decrease was due primarily to decreased construction activity for energy infrastructure projects versus 2002. Gross profit margins increased to 24% in 2003 from 21% in 2002, reflecting a change in the mix of projects constructed during the year. Gross profit margin in 2002 included a demand side management program that contributed $2.4 million in 2002 and was terminated at the end of the year. Gross profit margins trended upwards over 2002 due to the focus on more profitable performance contracting contracts as contrasted with less profitable energy infrastructure construction.
Revenue backlog increased to $134.2 million at year-end 2003 from $118.2 million at year-end 2002. The increase in backlog was primarily due to the award of federal government contracts in 2003.
Total operating expenses decreased by $6.4 million from $30.5 million in 2002 to $24.1 million in 2003. This decrease was primarily due to the $5.3 million impairment charge for the Jamaica power plant project in 2002. Additionally, SG&A expenses decreased to $22.7 million in 2003 from $23.5 million in 2002. Included in SG&A expenses in 2003 was $0.8 million related to the consolidation of the energy infrastructure and performance contracting groups and included in 2002 was $1.0 million related to office consolidations. The remaining $0.6 million decrease in SG&A was primarily due to a reduction in labor costs.
Equity earnings of nonconsolidated investments of $2.5 million in 2003 and $4.7 million in 2002 reflects NORESCO’s share of the earnings from its equity investments in power plant assets. The decrease in earnings was primarily due to decreased earnings from the Petroelectrica de Panama LDC Panamanian power plant because of the expiration of its power purchase agreement. Revenue in 2003 from a replacement agreement was lower than that recognized in 2002. Earnings were also lower due to the consolidation of Hunterdon Cogeneration, LP (Hunterdon) and Plymouth Cogeneration, LP (Plymouth) in 2003. These consolidations, as more fully described in Note 9 to the consolidated financial statements, required NORESCO to recognize minority interest expense of $0.5 million in 2003.
33
The Company reviewed its equity investment related to Petroelectrica de Panama LDC, an independent power plant in Panama, during the fourth quarter of 2003. As a result of the analysis performed, an impairment of $11.1 million in the fourth quarter of 2003 was recorded which represented the full value of NORESCO’s equity investment in the project.
Other Income Statement Items
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Gain on exchange of Westport for Kerr-McGee shares |
|
$ |
217,212 |
|
$ |
— |
|
$ |
— |
|
|
Charitable foundation contribution |
|
(18,226 |
) |
(9,279 |
) |
— |
|
|||
|
Gain on sale of available-for-sale securities |
|
3,024 |
|
13,985 |
|
— |
|
|||
|
Other income, net |
|
3,692 |
|
— |
|
— |
|
|||
|
Equity earnings (loss) of Westport |
|
— |
|
3,614 |
|
(8,476 |
) |
|||
As a result of the April 7, 2004 merger between Westport and Kerr-McGee, the Company recognized a gain of $217.2 million on the exchange of its Westport shares for Kerr-McGee shares. See Note 10 to the Company’s consolidated financial statements for further information on this transaction.
In the first quarter of 2003, the Company established Equitable Resources Foundation, Inc. to facilitate the Company’s charitable giving program. This foundation received additional funding in the second quarter of 2004. See Note 10 to the Company’s consolidated financial statements for information regarding the charitable foundation contribution expense recorded upon contributions of Kerr-McGee and Westport shares made to this foundation during 2004 and 2003.
During the second quarter of 2004, the Company sold 800,000 Kerr-McGee shares resulting in a gain of $3.0 million. During the fourth quarter 2003, the Company sold approximately 1.48 million shares of Westport, resulting in a gain of $14.0 million.
Other income, net includes $3.1 million of pre-tax dividend income recorded in 2004 relating to the Company’s 7.0 million Kerr-McGee shares. See section titled “Equitable Supply” for discussion of the remaining $0.6 million of other income related to Equitable Production.
The Company reported $3.6 million in equity earnings from its minority ownership in Westport during the first quarter 2003. At the end of the first quarter of 2003, the Company’s ownership position in Westport decreased below 20%. As a result of the decreased ownership, the Company changed the accounting treatment for its investment from the equity method to the available-for-sale method effective March 31, 2003.
Interest Expense
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Interest expense |
|
$ |
49,247 |
|
$ |
45,766 |
|
$ |
38,787 |
|
Interest expense increased by $3.4 million from 2003 to 2004 primarily due to increases in short-term borrowing activity during 2004 as well as an increase in the average annual short-term debt interest rate.
Interest expense increased by $7.0 million from 2002 to 2003 primarily due to the issuance of $200 million of Notes in November 2002 and the issuance of $200 million of Notes in February 2003. The stated interest rate for both issuances was 5.15%. The increase was partially offset by the redemption of $125 million of 7.35% trust preferred capital securities on April 23, 2003 as well as lower interest rates on short-term debt.
Average annual interest rates on the Company’s short-term debt were 1.7%, 1.2%, and 1.8% for 2004, 2003, and 2002, respectively.
34
Other Items
Cumulative Effect of Accounting Change
Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143 “Accounting for Asset Retirement Obligations” (Statement No. 143), which requires that the fair value of a liability for an asset retirement obligation be recognized by the Company at the time the obligation is incurred. The adoption of Statement No. 143 by the Company resulted in an after-tax charge to earnings of $3.6 million, which is reflected as the cumulative effect of accounting change in the Company’s Statement of Consolidated Income for the year ended December 31, 2003.
In accordance with the requirements of SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement No. 142), the Company tested its goodwill for impairment as of January 1, 2002. The Company’s goodwill balance as of January 1, 2002 totaled $57.2 million and was entirely related to the NORESCO segment. The fair value of the Company’s goodwill was estimated using discounted cash flow methodologies and market comparable information. As a result of the impairment test, the Company recognized an impairment of $5.5 million, net of tax, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment were expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment was reported as the cumulative effect of accounting change in the Company’s Statement of Consolidated Income for the year ended December 31, 2002. In the fourth quarter of 2004, 2003 and 2002, the Company performed the required annual impairment test of the carrying amount of goodwill and no further impairment was required.
Income from Discontinued Operations
In December 1998, the Company sold its natural gas midstream operations. A capital loss in connection with the sale was treated as a nondeductible item for tax reporting purposes under the then current Treasury regulations embodying the “loss disallowance rule,” resulting in additional tax recorded on this sale as a reduction to net income from discontinued operations. In May 2002, the Internal Revenue Service (IRS) issued new Treasury regulations interpreting the “loss disallowance rule” so as to permit this capital loss to be treated as deductible. During June 2002, the Company filed amended 1998 tax return filings. Consequently, in the second quarter 2002, the Company recorded a $9.0 million increase in net income from discontinued operations related to this unexpected tax benefit.
Capital Resources and Liquidity
Operating Activities
Cash flows provided by operating activities totaled $176.4 million in 2004 as compared to $121.0 million in 2003, a $55.4 million increase between years. The Company had increased collections from customers in 2004 as compared to 2003, driven primarily by increased net operating revenues in the Company’s Supply segment. During the year ended December 31, 2003, the Company made cash contributions totaling $51.8 million to its pension plan, while the Company did not make any such contributions in 2004. These increases in cash flow provided by operating activities were offset by a decrease in cash from operations of $36.8 million in 2004 resulting from the Company’s amendment of the prepaid forward contract in the second quarter of 2004. Cash flows from operations were also affected by other working capital changes during 2004.
When the Company’s two prepaid forward gas sale transactions were originally consummated in January of 2001, the Company reviewed the specific facts and circumstances related to these transactions to determine if the appropriate Statements of Consolidated Cash Flows presentation would be as an operating activity or a financing activity. The Company concluded that the appropriate accounting presentation of the prepaid forward gas sales transactions was as an operating cash flow item. Consistent with the Company’s previous presentation, the current presentation includes recognition of prepaid forward production revenues in operating activities. One of the Company’s two prepaid forward gas sales contracts expired on December 31, 2003. In June 2004, the remaining prepaid forward contract was amended, which resulted in the Company repaying the net present value of the portion of the prepayment related to undelivered quantities of natural gas in the original contract. As stated previously, this amendment resulted in the Company repaying $36.8 million and recognizing a loss of $5.5 million on the settlement
35
of the prepaid contract. As a result of the expiration of one prepaid contract and the amendment of the other, there was $45.3 million less prepaid forward production revenue recognized in 2004 compared to the prior year.
Cash flows provided by operating activities totaled $121.0 million in 2003 as compared to $214.5 million in 2002. The $93.5 million decrease in operating cash flows from 2002 to 2003 was primarily the result of the decrease in cash provided from working capital due to a large increase in inventory during 2003 as compared to a slight decrease in inventory during 2002. The increase in inventory was mainly due to increased natural gas prices and volumes stored in 2003 compared to the prior year. In addition, the Company made $51.8 million in pension contributions during 2003.
Investing Activities
Net cash flows used in investing activities totaled $157.9 million in 2004 as compared to $214.3 million in 2003 and $169.2 million in 2002.
The Company expended approximately $202.4 million in 2004 for capital expenditures as compared to $265.7 million in 2003 and $218.5 million in 2002. Equitable Supply spent $141.7 million in 2004, of which $91.5 million was spent on developmental drilling and $50.2 million was spent on infrastructure projects. Equitable Utilities spent $56.3 million in 2004, of which $48.5 million was spent on infrastructure projects, $3.2 million was spent on technology projects, and $4.6 million was spent on business development. Capital expenditures for Equitable Supply in 2003 included $44.2 million used for the purchase of the remaining limited partnership interest in ABP in February 2003.
The Company also received proceeds of $42.9 million in 2004 from the sale of 800,000 shares of the Company’s investment in Kerr-McGee.
In 2003, the sale of approximately 1.48 million shares of Westport stock in the fourth quarter of 2003 provided $38.4 million of proceeds. In addition, proceeds of $4.4 million were provided by the sale of the Company’s 50% interest in an equity investment in October 2003 and proceeds of $6.6 million were provided by the sale of wells in Ohio in February 2003.
Cash used in 2002 investing activities included $17.6 million invested in available-for-sale securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures.
Cash provided by investing activities in 2002 included $63.0 million of proceeds from the sale of oil-dominated fields within Equitable Supply. In December 2001, the Company sold its oil-dominated fields in order to focus on natural gas activities. The sale resulted in a decrease of 63 Bcfe of proved developed producing reserves and 5 Bcfe of proved undeveloped reserves. These proceeds were held in a restricted cash account at December 31, 2001 for use in a potential like-kind exchange for certain identified assets. During 2002, the restrictions lapsed and the cash was made available for operations.
A total of $293 million was authorized for the 2005 capital budget program, as previously described in the business segment results. The Company expects to finance this program with cash generated from operations and with short-term debt. See discussion in the “Short-term Borrowings” section below regarding the financing capacity of the Company.
Financing Activities
Net cash flows used in financing activities totaled $55.8 million in 2004 as compared to $112.9 million of cash flows provided by financing activities in 2003 and $57.2 million of cash flows used in financing activities in 2002.
The increase in cash flows used in financing activities from 2003 to 2004 is primarily attributable to the following items. During 2004 and 2003, the Company repurchased 2.4 million and 1.4 million shares of its outstanding common stock for $118.5 million and $55.2 million, respectively, resulting in a $63.3 million increase in cash flows used. Cash flows used in financing activities also increased due to a $29.0 million increase in
36
dividends paid in 2004 and a $75.0 million increase in long-term debt during 2003 due to the issuance of $200 million of notes and the redemption of $125 million of Trust Preferred Securities.
The increase in cash flows provided by financing activities from 2002 to 2003 was primarily the result of increased borrowing in 2003 as compared to 2002. Short-term borrowing activity resulted in a net cash inflow of $93.6 million in 2003 compared to a net cash outflow of $169.4 million in the prior year. The increase in cash flows from short-term borrowing activity in 2003 was partially offset by a decrease in cash provided by long-term debt as compared to the prior year. The Company issued $200 million of notes in February 2003 with a stated interest rate of 5.15% and a maturity date of March 2018. The proceeds from this issuance were used to retire the Company’s $125 million of 7.35% Trust Preferred Securities on April 23, 2003. This provided a net cash increase from the long-term debt issuance of $75 million in 2003 compared to a $200 million increase in 2002 relating to the November 2002 issuance of 5.15% notes. The $200 million long-term debt issuance in November 2002 was used to repay a significant portion of commercial paper and short-term loans. Other repayments and retirements of long-term debt were $24.7 million in 2003 compared to $0.6 million in 2002. Additionally, loan proceeds received from financial institutions associated with the sale of contract receivables were $45.5 million in 2003 compared to $23.2 million in 2002.
Short-term Borrowings
Cash required for operations is affected primarily by the seasonal nature of the Company’s natural gas distribution operations and the volatility of oil and natural gas commodity prices. Short-term loans are used mainly to support working capital requirements during the summer months and are repaid as natural gas is sold during the heating season.
The Company believes that it has adequate borrowing capacity to meet its financing requirements. Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements. Interest rates on these short-term loans averaged 1.7% during 2004. The Company maintains, with a group of banks, a three-year revolving credit agreement providing $500 million of available credit that expires in 2006. The credit agreement may be used for, among other things, credit support for the Company’s commercial paper program. As of December 31, 2004, the Company has the authority to arrange for a commercial paper program up to $650 million. The amount of commercial paper outstanding at December 31, 2004 is $295.5 million.
Due to continued increases in natural gas prices during 2004 and resulting increases in the Company’s net liability position under its natural gas swap agreements, the Company has borrowed additional amounts through its commercial paper program to fund its margin deposits under its exchange-traded natural gas agreements. See further discussion below under “Inflation and the Effect of Changing Energy Prices.”
In July of 2004, the Company entered into three 7.5 year secured variable share forward transactions to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares (see Note 3 to the Company’s consolidated financial statements). Each transaction permits receipt of an amount up to the net present value of the floor price prior to maturity. The economic characteristics of any receipt would be considered that of a borrowing.
The Company’s credit ratings, as determined by either Standard & Poor’s or Moody’s on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s credit rating, the higher the level of fees and borrowing rate. As of December 31, 2004, the Company had not borrowed any amounts against these lines of credit. Facility fees, averaging one-eleventh of one percent in both 2004 and 2003, were paid to maintain credit availability.
The Company believes that cash generated from operations, amounts available under its credit facilities and amounts which the Company could obtain in the debt and equity markets given its financial position, are more than adequate to meet the Company’s reasonably foreseeable liquidity requirements.
37
Financing Triggers
The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, sell assets, and certain other corporate actions. The covenants do not contain a rating trigger. Therefore, in the event that the Company’s debt rating changes, this event would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.
Inflation and the Effect of Changing Energy Prices
Due to the nature of the Company’s operations, fluctuations in natural gas prices can significantly impact its operating cash flows, and consequently, the availability of funds for use in both investing and financing activities. As a result of the increase in natural gas prices during the past several months, the Company’s liquidity position could be negatively affected by further increases. The increase in natural gas prices may be accompanied by or result in increased well drilling costs, as the demand for well drilling operations continues to increase; increased deferral of purchased gas costs for the Distribution operations (however, purchased gas costs are subsequently recoverable from utility customers in future months through gas cost adjustment clauses included in the Distribution operation’s filed rate tariffs); increased severance taxes, as the Company is subject to higher severance taxes due to increased volumes of gas extracted from the wells combined with increased value of the gas extracted from the wells; increased lease operating expenses due to increased demand for lease operating services; and increased exposure to credit losses resulting from potential increases in uncollectible accounts receivable from the Distribution operation’s customers. The Company’s risk management program and available borrowing capacity currently in place provide means for the Company to manage these risks. Furthermore, the inventory owned by the Company as reserves or in storage increases in value, thus increasing the creditworthiness of the Company and facilitating its ability to access the credit markets for additional liquidity if needed.
Due to continued increases in natural gas prices and resulting increases in the Company’s net liability position under its natural gas swap agreements, the Company has borrowed additional amounts through its commercial paper program to fund its margin deposits under its exchange-traded natural gas agreements. When the net fair value of any of the swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The margin deposits are remitted back to the Company in part or in full when the excess of the derivative liability over the agreed-upon threshold is reduced below the amount deposited. The Company has recorded such deposits in the amount of $36.0 million as accounts receivable in its Consolidated Balance Sheets as of December 31, 2004.
Commodity Risk Management
The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company hedges natural gas through financial instruments including forward contracts, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual agreements.
The fair value of these derivative commodity instruments was a $26.8 million asset and a $350.4 million liability as of December 31, 2004, and a $34.5 million asset and a $137.6 million liability as of December 31, 2003. These amounts are classified in the Consolidated Balance Sheets as derivative commodity instruments, at fair value. The net amount of derivative commodity instruments, at fair value, increased from a net liability of $103.1 million at December 31, 2003 to a net liability of $323.6 million at December 31, 2004, primarily as a result of the increase in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges total 432.6 Bcf and 347.2 Bcf as of December 31, 2004 and December 31, 2003, respectively, and primarily relate to natural gas swaps. The open swaps at December 31, 2004 have maturities extending through 2011.
38
Equitable has taken advantage of favorable gas prices to significantly hedge production. As of December 31, 2004, the approximate volumes and prices of Equitable’s hedges and fixed-price contracts for 2005 – 2007 are:
|
|
|
2005 |
|
2006 |
|
2007 |
|
|||
|
Volume (Bcf) |
|
63 |
|
62 |
|
59 |
|
|||
|
Average Price (NYMEX)* |
|
$ |
4.80 |
|
$ |
4.73 |
|
$ |
4.75 |
|
* The above price is based on a conversion rate of 1.05 MMbtu/Mcf.
With respect to hedging the Company’s exposure to changes in natural gas commodity prices, management’s objective is to provide price protection for the majority of expected production for the years 2005 through 2008, and for over 25% of expected equity production for the years 2009 through 2011. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is approximately $0.01 per diluted share in 2005 and $0.02 to $0.03 per diluted share for 2006 and 2007. Although the Company uses derivative instruments that create a price floor in order to provide downside protection while allowing the Company to participate in upward price movements through the use of collars and straight floors, the preponderance of instruments tend to be fixed price swaps or NYMEX-traded forwards. This approach avoids the higher cost of option instruments but limits the upside potential. The current high NYMEX gas prices may cause the Company to rely less heavily on natural gas swap agreements and futures contracts. The Company also engages in basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices.
On April 7, 2004, Westport announced a merger with Kerr-McGee. On June 25, 2004, Westport and Kerr-McGee announced that the two companies had completed their merger upon approval by the stockholders of each company. As a result of the transaction, the Company received 0.71 shares of Kerr-McGee for each Westport share owned. Prior to the merger, the Company owned 11.53 million shares, or 17%, of Westport, resulting in the Company receiving 8.2 million shares of Kerr-McGee. The Company accounted for the merger transaction in accordance with Emerging Issues Task Force No. 91-5, “Nonmonetary Exchange of Cost-Method Investments” (EITF 91-5). EITF 91-5 states that an investor in an acquired company that accounts for the investment under the cost-method shall record the transaction at fair value, resulting in a new basis and recognition of gains or losses in the income statement. Accordingly, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for Kerr-McGee shares in the second quarter of 2004. The Company recorded its book basis in the Kerr-McGee shares at $49.82 per share, which included a discount to the market price for trading restrictions on the securities. The discount was accreted into other comprehensive income during the third quarter of 2004.
Subsequent to the Kerr-McGee/Westport merger, the Company sold 800,000 Kerr-McGee shares for $42.8 million, thus resulting in a realized gain of $3.0 million in the second quarter of 2004. Additionally, on June 30, 2004, the Company irrevocably committed to contribute 357,000 Kerr-McGee shares to Equitable Resources Foundation, Inc.. This resulted in the Company recording a community-giving foundation contribution expense of $18.2 million during the second quarter 2004. The shares were transferred to this foundation in the third quarter of 2004.
In the third quarter of 2004, the Company entered into three variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares (See Note 3 to the Company’s consolidated financial statements). The variable share forward contracts, which contain collars, meet the requirements of SFAS No. 133 Implementation Issue G20, “Assessing and Measuring the Effectiveness of an Option used in a Cash Flow Hedge” and have been designated cash flow hedges. Under this guidance, complete hedging effectiveness is assumed and the entire fair value of the collar is recorded in other comprehensive income. These variable share forward contracts provide for limited downside in the underlying Kerr-McGee shares while continuing to maintain considerable exposure to potential upside in the value of Kerr-McGee. The collars effectively limit the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares between a blended average floor price per share of $53.06 and a blended average cap price per share of $100.79. The three tranches of contracts were allocated among three different counterparties in a bidding process designed to maximize the pricing of the collars while providing an opportunity to minimize any counterparty credit exposure. A variable portion of the dividends received on the underlying Kerr-McGee shares must be paid to each counterparty depending upon the hedged position of such counterparty. Based on the current hedged position of the counterparties, the
39
Company expects to pay to each counterparty approximately 67% of the next Kerr-McGee dividend. In the second half of 2004, the Company recorded pre-tax dividend income, net of payments to the counterparties, of $3.1 million, which is recorded in other income, net on the Statement of Consolidated Income for the year ended December 31, 2004. At December 31, 2004, the Company owns approximately 7.0 million Kerr-McGee shares, of which approximately 1.0 million shares remain unhedged. The Company is currently evaluating whether it can utilize the value of the unhedged shares effectively in a similar variable forward contract structure, or whether a sale or other course of action would constitute the best use of this asset.
Certain NORESCO projects are conducted through nonconsolidated entities that consist of private power generation facilities located in select international locations. During the second quarter of 2004, several negative circumstances caused the Company to reassess its international investments for additional impairments and to accelerate its plans to exit the international generation business. Changes in pricing in the electricity power market in Panama during the second quarter of 2004 negatively impacted the outlook for operations of IGC/ERI Pan Am Thermal Generating Limited (Pan Am), a Panamanian electric generation project. As a result, the Company performed an impairment analysis of its equity interest in this project. This involved preparing a probability-weighted cash flow analysis using the undiscounted future cash flows and comparing this amount to the book value of the equity investment. The probability-weighted cash flows resulted in a lower fair value than the carrying value, and an impairment was deemed necessary. An impairment of $22.1 million was recorded in the second quarter of 2004 and represents the full value of NORESCO’s equity investment in the project.
During 2004, the Company also reviewed its investment in Compania Hidroelectrica Dona Julia, S.D.R. Ltd. (Dona Julia), a Costa Rican electric generation project, as the investment was being actively marketed for sale. Based on the analysis performed on the sales value of the investment, the Company recorded an impairment charge of $2.8 million in the second quarter of 2004 to write down the investment to its fair value less costs to sell. Following the impairment, the investment in Dona Julia was considered held for sale. The investment was included in equity in nonconsolidated investments on the Consolidated Balance Sheet at December 31, 2004. In January 2005, the Company sold its interest in Dona Julia to a third party purchaser and recorded a slight gain on the sale in 2005.
Additional impairment charges of $15.3 million were also recorded in the second quarter of 2004 for total impairment charges of $40.2 million. The additional charges related to various costs and obligations related to exiting NORESCO’s investments in international power plant projects. Included in these charges was a liability for loan guarantees in the amount of $5.8 million in support of the 50% owned non-recourse financed energy project known as Pan Am (described above). The impairment charges were reviewed in the fourth quarter of 2004 and reduced by $0.6 million. The entire impairment charge has been included in international investments, primarily impairment on the Statement of Consolidated Income for the year ended December 31, 2004. The Company is actively evaluating alternatives for the sale and disposal of its international assets.
The Company reviewed its equity investment related to Petroelectrica de Panama LDC, an independent power plant in Panama, during the fourth quarter of 2003. As a result of the analysis performed, an impairment of $11.1 million in the fourth quarter of 2003 was recorded which represented the full value of NORESCO’s equity investment in the project. The plant has been dismantled and the proceeds from the sale of the plant’s engines will be used to cover the costs of remediation and final closure in 2005.
In June 2003, the Company reevaluated its interest in Hunterdon Cogeneration LP (Hunterdon) and concluded that the Company effectively controlled Hunterdon for consolidation purposes. As a result, the Company began consolidating Hunterdon’s financial condition, results of operations and cash flows as of June 30, 2003 in the NORESCO segment.
In 2000, Equitable Supply sold an interest in oil and gas properties to a trust, Appalachian Natural Gas Trust (ANGT). The Company retained a 1% interest in profits of ANGT and has separately negotiated arms-length, market-based rates with ANGT for gathering, marketing, and operating fees to deliver its natural gas to market. At December 31, 2004, the Company has a receivable recorded from ANGT totaling $1.4 million. This receivable resulted from inadvertent overpayments to ANGT for more than the amount due under the Net Profits Interest
40
Agreement. Under the terms of the agreement, the Company will deduct the overpayment from future payments to ANGT over an extended period of time.
Recently Issued Accounting Standards
In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN No. 46). FIN No. 46 required certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity did not have the characteristics of a controlling financial interest or did not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Prior to FIN No. 46, an entity was generally consolidated by an enterprise when the enterprise had a controlling financial interest through ownership of a majority voting interest in the entity. FIN No. 46 was effective for all new variable interest entities created or acquired after January 31, 2003. The Company adopted FIN No. 46 for variable interest entities created or acquired prior to February 1, 2003 as of July 1, 2003. The adoption of FIN No. 46 required the consolidation of Plymouth Cogeneration Limited Partnership (Plymouth), a joint venture entered into by NORESCO, and the deconsolidation of EAL/ERI Cogeneration Partners LP (Jamaica), which is the partnership that holds the Jamaican power plant.
In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R) that modified some of the provisions of FIN No. 46 and provided exemptions to certain entities from the original guidance. The Company adopted FIN No. 46R in the first quarter of 2004. The adoption of FIN No. 46R required the Company to deconsolidate Plymouth as of January 1, 2004, due to certain modifications of the original FIN No. 46 provisions.
This deconsolidation returned Plymouth to the equity method of accounting for investments. The Company restored the equity investment in Plymouth of $0.1 million and decreased minority interest by $0.6 million in the Consolidated Balance Sheet. As of January 1, 2004, $4.9 million of assets and $4.9 million of liabilities, including nonrecourse debt of $4.0 million, were removed from the Consolidated Balance Sheet.
The Company also has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which Equitable was not deemed to be the primary beneficiary. As of December 31, 2004, ANPI had $255.5 million of total assets and $312.6 million of total liabilities (including $172.9 million of long-term debt, including current maturities), excluding minority interest. The Company’s maximum exposure to a loss as a result of its involvement with ANPI is estimated to be approximately $29 million.
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R). This guidance replaced previously-existing requirements under SFAS 123, “Accounting for Stock-Based Compensation” (Statement No. 123), and APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Statement No. 123R eliminates the ability for an entity to account for stock-based compensation transactions using the intrinsic value method of APB No. 25. Under Statement No. 123R, an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award would generally be measured based on the grant-date fair value of the award. Statement No. 123R will be effective for public entities in the first interim or annual period beginning after June 15, 2005. While the impact of adoption of Statement No. 123R cannot be determined at this time, the Company will continue to evaluate the impact of this guidance on the Company’s financial position and results of operations. Had the Company adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share in Note 1 to the consolidated financial statements.
On June 17, 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” The proposed interpretation would clarify that a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A recording of the liability at fair value would be recognized for a conditional asset retirement obligation when the liability is incurred. Certain factors regarding the timing and method of the settlement, which are conditional upon the future events occurring, would be factored into the measurement of the liability rather than the recognition of the liability. The final rules are expected to be
41
issued in early 2005 and are anticipated to be effective no later than the end of the fiscal year ending after December 15, 2005. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final rules are issued.
Off-Balance Sheet Arrangements
The Company issued a liquidity reserve guarantee to ANPI, which is subject to certain restrictions and limitations, and is secured by the fair market value of the assets purchased by ANGT. The Company received a market-based fee for the issuance of the reserve guarantee. As of December 31, 2004, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be $29 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45), and has not been modified subsequent to issuance.
The Company has certain minority investments representing ownership interests in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. The Company has entered into agreements with these entities to provide gathering and operating services to deliver their gas to market. In addition, the Company receives a marketing fee for the sale of gas based on the net revenue for gas delivered. The total revenue earned from these fees totaled approximately $24.9 million for the year ended December 31, 2004. Revenue from these fees will be affected by the purchase of the 99% limited partnership interest in ESP, which occurred in January 2005 and is more fully discussed under the section “Equitable Supply.”
In order to accelerate cash collections, the NORESCO segment executes transactions to sell certain contract receivables to a financial institution and a variable interest entity. The variable interest entity is a multi-seller conduit that purchases contract receivables from several energy companies. The Company has no ownership interest in or control of the variable interest entity. As further described in Note 1 to the consolidated financial statements, the Company does not retain any interest in the contract receivables once the sale is complete. For the year ended December 31, 2004, approximately $53.8 million of the contract receivables met the criteria for sales treatment.
Pension Plans
The Company made cash contributions totaling $49.6 million to its pension plan during the first three quarters of 2003. In accordance with current funding guidelines, these contributions were designated as 2002 plan year contributions and, in the aggregate, represent the maximum allowable contribution that the Company could make to its pension plan for that plan year. In the fourth quarter of 2003, the Company made an additional cash contribution totaling $2.2 million to its pension plan. In accordance with current funding guidelines, this contribution was designated as a 2003 plan year contribution. As a result of the cash contributions, the Company’s minimum funding requirement was zero for the 2004 plan year. The Company was not required to, and consequently did not make any contribution to its pension plans during the years ended December 31, 2004 and 2002. The Company expects to make a cash contribution of $10.3 million to its pension plan during 2005 to fully fund the cash balance participants portion of the pension plan which was settled effective December 31, 2004.
The following benefit payments, which reflect expected future service and the final settlement of the cash balance portion of the pension plan in 2005, are expected to be paid during each of the next five years and the five years thereafter: $28.2 million in 2005; $8.2 million in 2006; $8.1 million in 2007; $7.7 million in 2008; $8.3 million in 2009; and $37.5 million in the five years thereafter.
The reduction in the fair market value of the Company’s pension plan assets over the period of 2000 to 2002, coupled with decreases in the expected rate of return on pension plan assets and increases in the amount of unrecognized actuarial losses, has also contributed to increases in the amount of pension expense recognized by the Company. Total pension expense recognized by the Company in 2004, 2003, and 2002, excluding special termination benefits, one-time settlement expenses and curtailment losses, totaled $0.8 million, $5.1 million, and $5.3 million, respectively. In the fourth quarter of 2003, the Company froze the pension benefit provided through a
42
defined benefit plan to approximately 340 non-represented employees. The Company now provides benefits to these employees under a defined contribution plan that covers all other non-represented employees of the Company. In the fourth quarter of 2004, the Company irrevocably committed to settle the pension obligation of those non-represented employees whose benefits were frozen in 2003. As a result of this settlement, which was accounted for under SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a one-time settlement expense of $13.4 million as of December 31, 2004. The settlement expense that was recognized for these non-represented employees was primarily the result of accelerated recognition of approximately $11.0 million in previously deferred unrecognized losses. The accelerated recognition of the previously deferred unrecognized losses, along with a reduced number of retirees obtaining benefits in the future, will decrease the expected amount of pension expense to be recognized by the Company in future years. As a result of this settlement, the projected benefit obligation of the pension plan is expected to be reduced by approximately $19.6 million. Additionally, the pension settlement expense is an unallocated expense in deriving total operating income for segment reporting purposes. See Note 2 to the Company’s consolidated financial statements. Additionally, the projected future pension expense is expected to decrease as a result of the settlement of the cash balance portion of the pension plan.
Incentive Compensation
The Company continues to shift its compensation focus from stock options to performance-based stock units and time-restricted stock awards. Management and the Board of Directors believe that such an incentive compensation approach more closely aligns management’s incentives with shareholder rewards than is the case with traditional stock options. The Company has long utilized time-restricted stock in its compensation plans, but only began issuing performance-restricted units in 2002 and has now fully transitioned to a long-term incentive approach that is limited to performance-restricted stock or units and time-restricted stock. No stock options were awarded in 2004.
The Company recorded the following incentive compensation expense for the periods indicated below:
|
|
|
Year Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Millions) |
|
|
|
|||
|
Short-term incentive compensation expense |
|
$ |
15.8 |
|
$ |
10.5 |
|
$ |
12.1 |
|
|
Long-term incentive compensation expense |
|
30.0 |
|
17.6 |
|
9.1 |
|
|||
|
Total incentive compensation expense |
|
$ |
45.8 |
|
$ |
28.1 |
|
$ |
21.2 |
|
Much of the $17.7 million increase from 2003 to 2004 was due, directly and indirectly, to the culmination of the Kerr-McGee/Westport merger. The long-term incentive compensation expenses are primarily associated with executive performance incentive programs that were instituted starting in 2002. The Company currently estimates 2005 total incentive compensation expense of approximately $34 million.
On February 23, 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. Under the program a maximum of 600,000 stock units may be granted among a maximum of forty participants. The vesting of these stock units will occur on December 31, 2008, contingent upon a combination of the level of total shareholder return relative to 29 peer companies and the Company’s average absolute return on total capital during the four year performance period. As a result, zero to 1,500,000 units (250% of the units available for grant) may be distributed in cash or stock. The 29 peer companies are identical to the peer group identified for the 2003 Executive Performance Incentive Program in Note 19 to the consolidated financial statements except for the exclusion of NUI Corp. The 2005 program will be accounted for as a variable plan and expensed over the four year performance period based on anticipated stock price and expected level of performance.
Federal Legislation
As a result of the Company’s increased partnership interest in ABP in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit attributable to ABP. This resulted in a reduction of the Company’s effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002, and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future. On November 18, 2003, the Energy Policy Act of 2003 (H.R. 6) was passed by the House of Representatives. This comprehensive energy policy legislation, as reported by conferees from the House of Representatives and the Senate, included an extension of the nonconventional fuels tax credit for existing qualifying wells and for newly drilled qualifying wells. The Senate was unable to pass H.R. 6 before adjourning for 2003 due to a lack of votes needed to avoid a threatened filibuster. Energy tax legislation continues to be discussed by the Senate and House of Representatives from time to time, but any extension of the nonconventional fuels tax credit continues to remain uncertain.
On September 30, 2003, the enabling legislation for the performance contracting work that NORESCO performs for the federal government under the Department of Energy contracts lapsed. On October 28, 2004, the
43
President signed legislation extending the contracting period for performance contracting at federal government facilities through October 2006.
During October 2004, Congress passed the American Jobs Creation Act of 2004 (the Jobs Creation Act), which the President signed into law on October 22, 2004. The Jobs Creation Act is the first major corporate tax act in a number of years. Some of the key provisions of the Jobs Creation Act include a new domestic manufacturing deduction, a temporary incentive for U.S. multinationals to repatriate foreign earnings, oil and gas producer incentives (not an extension of the nonconventional fuels tax credit), new tax shelter penalties, restrictions on deferred compensation and numerous other issue-specific provisions aimed at specific transactions. The only item in this legislation impacting the Company’s consolidated financial statements during 2004 was the temporary incentive to repatriate foreign earnings (see Note 6 to the consolidated financial statements).
Rate Regulation
The Company’s Distribution operations are subject to comprehensive regulation by the PA PUC and the Public Service Commission of West Virginia, and to rate regulation by the Kentucky Public Service Commission. The Company’s interstate pipeline operations are subject to rate regulation by the FERC. Accounting for the Company’s regulated operations is performed in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As described in Notes 1 and 11 to the consolidated financial statements, regulatory assets and liabilities are recorded to reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of the deferred costs.
Schedule of Contractual Obligations
The following table details the future projected payments associated with the Company’s contractual obligations as of December 31, 2004.
|
|
|
Total |
|
2005 |
|
2006-2007 |
|
2008-2009 |
|
2010+ |
|
|||||
|
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
|||||
|
Interest expense |
|
$ |
507,676 |
|
$ |
38,219 |
|
$ |
74,981 |
|
$ |
73,526 |
|
$ |
320,950 |
|
|
Long-term debt |
|
628,351 |
|
10,582 |
|
14,335 |
|
4,300 |
|
599,134 |
|
|||||
|
Operating leases |
|
66,939 |
|
6,663 |
|
13,525 |
|
9,198 |
|
37,553 |
|
|||||
|
Purchase obligations |
|
174,060 |
|
29,896 |
|
52,659 |
|
37,757 |
|
53,748 |
|
|||||
|
Other long-term liabilities |
|
42,870 |
|
— |
|
42,870 |
|
— |
|
— |
|
|||||
|
Total contractual obligations |
|
$ |
1,419,896 |
|
$ |
85,360 |
|
$ |
198,370 |
|
$ |
124,781 |
|
$ |
1,011,385 |
|
Operating leases are primarily entered into for various office locations and warehouse buildings, as well as a limited amount of equipment. In the third quarter of 2003, the Company entered into a long-term lease with Continental Real Estate Companies (Continental) to occupy office space in a building at the North Shore in Pittsburgh. This action will help consolidate the Company’s administrative operations. Continental is constructing and will own the office building, which is expected to be completed in 2005. The term of the lease is 20 years and nine months and the base rent is approximately $2 million per year. Relocation of operations from locations that utilize space under long-term leases will likely cause additional expense in 2005. The base rent payments of approximately $2 million per year have been included in the table above with payments commencing in 2006.
Included within the purchase obligations amount in the table above are annual commitments of approximately $29.7 million relating to the Company’s natural gas distribution and production operations for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to eleven years at December 31, 2004. Approximately $20.3 million of these costs are believed to be recoverable in customer rates.
The other long-term liabilities line represents the total estimated payout for the 2003 Executive Performance Incentive Program payable in the first quarter of 2006. See section titled “Critical Accounting Policies Involving Significant Estimates” and Note 19 to the consolidated financial statements for further discussion regarding factors that affect the ultimate amount of payout under this program.
44
Contingent Liabilities and Commitments
In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.
After an extended period of troubled operations, ERI JAM, LLC, a subsidiary that holds the Company’s interest in EAL/ERI Cogeneration Partners LP, an international infrastructure project located in Jamaica, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. In the third quarter 2003, ERI JAM, LLC transferred control of the international infrastructure project under the partnership agreement to the other non-affiliate general partner. The international infrastructure project was deconsolidated in accordance with FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.” In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM LLC as Debtor-in-Possession in the Chapter 11 case. EAL, an affiliate of JBG, is a limited partner in EAL/ERI Cogeneration Partners LP. In October 2003, JBG and EAL also filed a multi-count complaint seeking damages against Equitable and certain of its affiliates in U.S. District Court (Western District of Pennsylvania) alleging breach of contract, tortious interference with contractual relations, negligence and a variety of related claims with respect to the operation and management of EAL/ERI Cogeneration Partners LP. Equitable filed a Motion to Dismiss in September 2004, and subsequently agreed in principle with JBG and EAL to settle the litigation. The parties are currently negotiating the terms of a settlement agreement.
The various regulatory authorities that oversee Equitable’s operations will, from time to time, make inquiries or investigations into the activities of the Company. It is the Company’s policy to comply with applicable laws and cooperate when regulatory bodies make requests.
The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations. The Company has identified situations that require remedial action for which approximately $2.8 million is included in other long-term liabilities at December 31, 2004.
At the end of the useful life of a well the Company is required to remediate the site by plugging and abandoning the well. Costs associated with this obligation totaled $0.7 million, $1.3 million, and $0.7 million during the years ended 2004, 2003, and 2002, respectively.
In the second quarter of 2004, the Company established a liability for a guarantee in the amount of $5.8 million in support of a 50% owned non-recourse financed energy project in Panama. The guarantee covers a project loan debt service reserve requirement. The guarantee was included as part of the entire impairment charge of $39.6 million, which has been included as international investments, primarily impairment, on the Statements of Consolidated Income for the year ended December 31, 2004.
Audit Committee
The Audit Committee, composed entirely of independent directors, meets periodically with Equitable’s independent auditors and management to review the Company’s financial statements and the results of audit activities. The Audit Committee, in turn, reports to the Board of Directors on the results of its review and selects the independent auditors.
45
Transactions with Directors’ Affiliated Companies
In the course of ordinary business, the Company may have engaged in transactions with companies and organizations for which an Equitable Resources director serves as an officer. Those directors did not have a material interest in any such transactions and none of those transactions exceeded 5% of the gross revenues of either Equitable Resources or the other organization. Moreover, any such transactions were entered into on arms-length terms believed to be fair.
The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of this Form 10-K. The discussion and analysis of the financial statements and results of operations are based upon Equitable’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. The following critical accounting policies relate to the Company’s more significant judgments and estimates used in the preparation of its consolidated financial statements. There can be no assurance that actual results will not differ from those estimates.
Asset Impairment: The Company is required to test for asset impairment whenever events or changes in circumstances indicate that the carrying value of an asset might not be recoverable. The Company applies SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement No. 144), in order to determine whether or not an asset is impaired. This Statement indicates that if the sum of the future expected cash flows associated with an asset, undiscounted and without interest charges, is less than the carrying value, an asset impairment must be recognized in the financial statements. The amount of the impairment is the difference between the fair value of the asset and the carrying value of the asset.
The Company believes that the accounting estimate related to an asset impairment is a “critical accounting estimate” as it is highly susceptible to change from period to period, because it requires management to make assumptions about cash flows over future years. These assumptions affect the amount of an impairment, which would have an impact on the income statement. Management’s assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to do so in the future.
Additionally, the Company holds several investments in nonconsolidated entities that are accounted for under the equity method. Accounting Principles Board No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB No. 18), requires a company to recognize a loss in the value of an equity method investment which is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable. This is a “critical accounting estimate” for reasons similar to those described above regarding assumptions about future cash flows.
During the second quarter of 2004, several negative circumstances caused the Company to evaluate its international investments for additional impairments and to accelerate its plans to exit the international generation business. See “Equity in Nonconsolidated Investments” in Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 9 to the consolidated financial statements for further information regarding the impairment analysis performed in the second quarter of 2004.
Goodwill: Beginning in fiscal year 2002, goodwill was required to be evaluated annually for impairment, in accordance with Statement No. 142. This Statement requires that a two-step process be performed to analyze whether or not goodwill has been impaired. Step one is to test for potential impairment, which requires that the fair value of the reporting unit be compared to its book value. If the fair value is higher than the book value, no impairment occurs. If the fair value is lower than the book value, step two must be performed. Step two requires measurement of the amount of impairment loss, if any, and requires that a hypothetical purchase price allocation be done to determine the implied fair value of goodwill. The resulting fair value is then compared to the carrying value of goodwill. If the implied fair value of the goodwill is lower than the carrying value of the goodwill, an impairment must be recorded.
46
The Company believes that the accounting estimate related to the goodwill impairment is a “critical accounting estimate” because the underlying assumptions used for the discounted cash flow can change from period to period and these changes could cause a material impact to the income statement. Management’s assumptions about discount rates, inflation rates and other internal and external economic conditions, such as expected growth rate, require significant judgment based on fluctuating rates and anticipated future revenues. Additionally, Statement No. 142 requires that the goodwill be analyzed for impairment on an annual basis using the assumptions that apply at the time the analysis is updated.
As discussed in Note 12 to the consolidated financial statements, goodwill recorded was analyzed for impairment with the implementation of Statement No. 142. In 2002, the fair value of the Company’s goodwill (all of which related to NORESCO) was estimated using discounted cash flow methodologies and market comparable information. Based on the analysis, the implied fair value of the goodwill was less than the book value recorded for the goodwill. Therefore, the Company recognized an impairment. During the first quarter of 2002, the implied fair value of the goodwill, using the discounted cash flows methodology, was $51.7 million. The carrying value of the goodwill was $57.2 million, resulting in an after tax impairment charge of $5.5 million. In the fourth quarters of 2004, 2003 and 2002, the Company performed the required annual impairment test of the carrying amount of goodwill and no further impairment was required.
Allowance for Doubtful Accounts: The Company’s Utility division, Equitable Gas Company, encounters risks associated with the collection of its accounts receivable. As such, Equitable Gas Company records a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, Equitable Gas primarily utilizes a historical rate of accounts receivable “write-offs” as a percentage of total revenue. This historical rate is applied to the current revenues on a monthly basis. For 2004, the monthly provision was established at 4% of residential sales. Periodically, the reserve is reviewed for reasonableness. The historical rate is updated periodically based on events that may change the rate such as a significant increase or decrease in commodity prices or a significant change in the weather. Both of these items ultimately impact the customers’ ability to pay and the rates that are charged to the customers due to the pass through of purchased gas costs to the customers.
The Company believes that the accounting estimate related to the allowance for doubtful accounts is a “critical accounting estimate” because the underlying assumptions used for the allowance can change from period to period and the changes in the allowance could potentially cause a material impact to the income statement and working capital. The actual weather, commodity prices, and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from management’s assumptions and may impact expected operating income. The regulatory environment allows certain customers to enter into long-term payment arrangements, the ultimate collectibility of which is difficult to determine. Additionally, management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time.
Performance Plan: The Company accounts for stock-based compensation awards under APB No. 25. The Company treats its 2003 Executive Performance Incentive Program (2003 Plan) under which grants were awarded in 2003 as a variable plan.
The actual cost to be recorded for the plan is not known until the measurement date, which is in December 2005 for the 2003 Plan, requiring the Company to estimate the total expense to be recognized. The number of shares to be awarded in the plan is dependent upon attainment of certain total shareholder return performance goals relative to the performance of a peer group. In the current period, the Company estimated that the performance measures would be met at 167% of the full value of the shares for the 2003 Plan and that the estimated end of 2005 share price would be $62.50.
The Company believes that the accounting estimate related to the performance plan is a “critical accounting estimate” because it is likely to change from period to period based on the market price of the shares and the performance of the peer group. Additionally, the impact on the Statement of Consolidated Income of these changes could be material. Management’s assumptions about future stock price and the amount of the payment to ultimately be made requires significant judgment due to the volatility of the stock market.
Pension Plans: The calculation of the Company’s net periodic benefit cost (pension expense) and benefit obligation (pension liability) associated with its defined benefit pension plan (pension plan) requires the use of a number of assumptions that the Company deems to be “critical accounting estimates.” Changes in these
47
assumptions can result in different pension expense and liability amounts, and actual experience can differ from these assumptions. The Company believes that the two most critical assumptions are the expected long-term rate of return on plan assets and the discount rate.
The expected long-term rate of return reflects the average rate of earnings expected on funds invested or to be invested in the pension plan to provide for the benefits included in the pension liability. The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon information available to the Company at that time, including the pension plan’s investment mix and the historical and forecasted rates of return on these types of securities. The pension plan’s investment mix as of January 1, 2004 and 2005 approximated 60% equity securities and 40% fixed income securities. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (Statement No. 87). Although the long-term rate is intended to be fairly consistent, the Company has reevaluated and reduced the rate at the beginning of both 2003 and 2004. The expected long-term rate of return determined by the Company was 8.25% at both January 1, 2004 and 2005. Pension expense increases as the expected long-term rate of return decreases. Lowering the expected long-term rate of return by 0.5% (from 8.25% to 7.75%) as of January 1, 2005 would increase the Company’s projected net periodic pension expense by approximately $0.6 million.
The assumed discount rate reflects the current rate at which the pension benefits could effectively be settled. In estimating that rate, Statement No. 87 requires, and the Company looks to, rates of return on high quality, fixed income investments. The Company discounted its future pension liabilities using rates of 6.00% and 6.25% as of December 31, 2004 and 2003, respectively. The Company’s pension liability increases as the discount rate is reduced. Lowering the discount rate by 0.5% (from 6.00% to 5.50%) would increase the Company’s projected benefit obligation as of December 31, 2004 by approximately $4.3 million. Additionally, had the Company’s discount rate decreased to 5.50% as of December 31, 2004, the Company’s net periodic pension expense for 2005 would be projected to increase by approximately $0.2 million, as a significant portion of the pension plan’s participants are retirees.
Income Taxes: The Company accounts for income taxes under the provisions of SFAS No. 109, “Accounting for Income Taxes” (Statement No. 109). Statement No. 109 requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Please read Note 6 to the Company’s consolidated financial statements for further discussion.
The Company believes that the accounting estimate related to income taxes is a “critical accounting estimate” because the process of preparing the consolidated financial statements requires the Company to estimate the income tax expense in each jurisdiction in which the Company operates. This process involves estimating the actual current tax liabilities and reserves together with assessing the tax effect of temporary differences resulting from differing treatment of items, such as intangible drilling costs, other comprehensive income and depreciation of other fixed assets, for tax and accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included within the Consolidated Balance Sheets.
The Company must then assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that it is believed to be more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, a valuation allowance must be established. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about the Company’s current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including the Company’s anticipated future performance, the reversal of deferred tax liabilities, and tax planning strategies available to the Company. To the extent that a valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the statements of consolidated income. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets.
The Company has recorded deferred tax assets principally resulting from alternative minimum tax credits, deferred revenues and expenses, and state net operating loss carryforwards. The Company has established a
48
valuation allowance against the deferred tax assets related to the state net operating loss carryforwards, as it is believed that it is more likely than not that these deferred tax assets will not all be realized. No other valuation allowances have been established as it is believed that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these assets. Any change in the valuation allowance would impact the Company’s income tax expense and net income in the period in which such a determination is made.
49
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of Equitable through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment. The Company’s use of derivatives to reduce the effect of this volatility is described in Notes 1 and 3 to the consolidated financial statements. The Company uses simple, nonleveraged derivative instruments that are placed with major financial institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit the exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.
For commodity price derivatives used to hedge forecasted Company production, Equitable sets policy limits relative to the expected production and sales levels, which are exposed to price risk. These financial instruments include forward contracts, swap agreements (which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity), options and other contractual agreements. The level of price exposure is limited by the value at risk limits allowed by this policy. Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. In general, Equitable’s strategy is to become more highly hedged for production over the next several years at prices considered to be at the upper end of historical levels. The Company believes that prices between $3.00 and $3.50 per Mcf are sustainable in the long-term. Above this range, non-traditional supplies become economically feasible. Furthermore, the Company expects price volatility to result in prices significantly higher and lower than this range. The Company attempts to take advantage of these price fluctuations by hedging more aggressively when prices are much higher than the range and by taking more price risk when prices are significantly below the range. However, the Company has typically not hedged material volumes unless the natural gas prices exceed $4.00 per Mcf. The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility.
For commodity price derivatives held for trading purposes, the marketing group will engage in financial transactions also subject to policies that limit the net positions to specific value at risk limits. These financial instruments include forward contracts, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual agreements.
With respect to the energy derivatives held by the Company for purposes other than trading as of December 31, 2004, the Company continued to execute its hedging strategy by utilizing price swaps of approximately 314.9 Bcf of natural gas. These derivatives have hedged varying levels of expected equity production through 2011. A decrease of 10% in the market price of natural gas from the December 31, 2004 levels would increase the fair value of the natural gas instruments by approximately $185.8 million. An increase of 10% in the market price of natural gas would decrease the fair market value by the same amount.
With respect to derivative contracts held by the Company for trading purposes as of December 31, 2004, a decrease of 10% in the market price of natural gas from the December 31, 2004 level would decrease the fair market value by approximately $0.1 million. An increase of 10% in market price of natural gas from the December 31, 2004 level would increase the fair market value the same amount.
The Company determined the change in the fair value of the natural gas instruments using a method similar to its normal change in fair value as described in Note 1 to the consolidated financial statements. The Company assumed a 10% change in the price of natural gas from its levels at December 31, 2004. The price change was then applied to the natural gas instruments recorded on the Company’s balance sheet, resulting in the change in fair value.
The above analysis of the energy derivatives held by the Company for purposes other than trading does not include the unfavorable impact that the same hypothetical price movement would have on the Company and its subsidiaries’ physical sales of natural gas. The portfolio of energy derivatives held for risk management purposes approximates the notional quantity of the expected or committed transaction volume of physical commodities with
50
commodity price risk for the same time periods. Furthermore, the energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk, and as applicable, anticipated transactions occur as expected.
The disclosure with respect to the energy derivatives relies on the assumption that the contracts will exist parallel to the underlying physical transactions. If the underlying transactions or positions are liquidated prior to the maturity of the energy derivatives, a loss on the financial instruments may occur, or the derivative might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
In the third quarter of 2004, the Company entered into three variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares. The variable share forward contracts, which contain collars, meet the requirements of SFAS No. 133 Implementation Issue G20, “Assessing and Measuring the Effectiveness of an Option used in a Cash Flow Hedge” and have been designated as cash flow hedges. Under this guidance, complete hedging effectiveness is assumed and the entire fair value of the collar is recorded in other comprehensive income. These variable share forward contracts provide tax efficient monetization alternatives for the now limited downside in the underlying Kerr-McGee shares while continuing to maintain considerable exposure to potential upside in the value of Kerr-McGee. The three tranches of contracts represent the hedging of 6.0 million of the Kerr-McGee shares received as merger consideration and were allocated among three different counterparties in a bidding process designed to maximize the pricing of the collars while providing an opportunity to minimize any counterparty credit exposure. The remaining unhedged Kerr-McGee shares owned by the Company and not committed to the foundation after entering into these contracts is approximately 1.0 million shares. The Company is currently evaluating whether it can utilize the value of the unhedged shares effectively in a similar variable forward contract structure, or whether a sale or other course of action would constitute the best use of this asset.
The Company has variable rate short-term debt. As such, there is some limited exposure to future earnings due to changes in interest rates. A 100 basis point increase or decrease in interest rates would not have a significant impact on future earnings of the Company under its current capital structure. The Company maintains fixed rate long-term debt that is not subject to fluctuating interest rates.
The Company may enter into interest rate derivative instruments to mitigate exposure to future changes in interest rates, but as of December 31, 2004 the Company had no such instruments outstanding.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. NYMEX traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength.
See Notes 1 and 3 regarding Derivative Commodity Instruments in the notes to the consolidated financial statements and the “Commodity Risk Management” section contained in the Capital Resources and Liquidity section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information.
See “Inflation and the Effect of Changing Energy Prices” in Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion regarding the effect of fluctuations in natural gas prices on the Company’s operations.
51
Item 8. Financial Statements and Supplementary Data
|
|
|
|
|
|
|
Statements of Consolidated Income for each of the three years in the period ended December 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets as of December 31, 2004 and 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
52
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
Equitable Resources, Inc.
We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc. and Subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, in 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Asset Retirement Obligations” and of Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.”
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Equitable Resources, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 16, 2005, expressed an unqualified opinion thereon.
|
|
/s/ Ernst & Young LLP |
|
Pittsburgh, Pennsylvania
February 16, 2005
53
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The
Board of Directors and Shareholders
Equitable Resources, Inc.
We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting and appearing in the accompanying Item 9A Controls and Procedures, that Equitable Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Equitable Resources, Inc.’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 an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
We conducted our audit 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. Our audit included 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 considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
In our opinion, management’s assessment that Equitable Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Equitable Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004 and our report dated February 16, 2005 expressed an unqualified opinion thereon.
|
|
/s/ Ernst & Young LLP |
|
Pittsburgh, Pennsylvania
February 16, 2005
54
EQUITABLE RESOURCES, INC. AND
SUBSIDIARIES
STATEMENTS OF CONSOLIDATED
INCOME
YEARS ENDED DECEMBER 31,
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
(Thousands except per share amounts) |
|
|||||||
|
|
|
|
|
|
|
|
|
|||
|
Operating revenues |
|
$ |
1,191,609 |
|
$ |
1,047,277 |
|
$ |
1,069,068 |
|
|
Cost of sales |
|
519,140 |
|
428,706 |
|
506,363 |
|
|||
|
Net operating revenues (see Note 1) |
|
672,469 |
|
618,571 |
|
562,705 |
|
|||
|
Operating expenses: |
|
|
|
|
|
|
|
|||
|
Operation and maintenance |
|
87,988 |
|
76,319 |
|
73,430 |
|
|||
|
Production |
|
43,274 |
|
35,687 |
|
27,111 |
|
|||
|
Selling, general and administrative |
|
153,493 |
|
126,210 |
|
109,825 |
|
|||
|
Impairment of long-lived assets |
|
— |
|
— |
|
5,320 |
|
|||
|
Depreciation, depletion and amortization |
|
83,063 |
|
78,138 |
|
69,448 |
|
|||
|
Total operating expenses (see Note 1) |
|
367,818 |
|
316,354 |
|
285,134 |
|
|||
|
Operating income |
|
304,651 |
|
302,217 |
|
277,571 |
|
|||
|
Gain on exchange of Westport for Kerr-McGee shares |
|
217,212 |
|
— |
|
— |
|
|||
|
Charitable foundation contribution |
|
(18,226 |
) |
(9,279 |
) |
— |
|
|||
|
Gain on sale of available-for-sale securities |
|
3,024 |
|
13,985 |
|
— |
|
|||
|
Equity (losses) earnings from nonconsolidated investments: |
|
|
|
|
|
|
|
|||
|
Westport |
|
— |
|
3,614 |
|
(8,476 |
) |
|||
|
International investments, primarily impairment |
|
(39,590 |
) |
(11,059 |
) |
— |
|
|||
|
Other |
|
2,008 |
|
3,050 |
|
5,013 |
|
|||
|
|
|
(37,582 |
) |
(4,395 |
) |
(3,463 |
) |
|||
|
Other income, net |
|
3,692 |
|
— |
|
— |
|
|||
|
Minority interest |
|
(976 |
) |
(1,413 |
) |
(7,103 |
) |
|||
|
Interest expense |
|
49,247 |
|
45,766 |
|
38,787 |
|
|||
|
Income from continuing operations before income taxes and cumulative effect of accounting change |
|
422,548 |
|
255,349 |
|
228,218 |
|
|||
|
Income taxes |
|
142,694 |
|
81,792 |
|
77,592 |
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
279,854 |
|
173,557 |
|
150,626 |
|
|||
|
Income from discontinued operations |
|
— |
|
— |
|
9,000 |
|
|||
|
Cumulative effect of accounting change, net of tax |
|
— |
|
(3,556 |
) |
(5,519 |
) |
|||
|
Net income |
|
$ |
279,854 |
|
$ |
170,001 |
|
$ |
154,107 |
|
|
Earnings per share of common stock: |
|
|
|
|
|
|
|
|||
|
Basic: |
|
|
|
|
|
|
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
$ |
4.54 |
|
$ |
2.80 |
|
$ |
2.40 |
|
|
Income from discontinued operations |
|
— |
|
— |
|
0.14 |
|
|||
|
Cumulative effect of accounting change, net of tax |
|
— |
|
(0.06 |
) |
(0.09 |
) |
|||
|
Net Income |
|
$ |
4.54 |
|
$ |
2.74 |
|
$ |
2.45 |
|
|
Diluted: |
|
|
|
|
|
|
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
$ |
4.44 |
|
$ |
2.74 |
|
$ |
2.36 |
|
|
Income from discontinued operations |
|
— |
|
— |
|
0.14 |
|
|||
|
Cumulative effect of accounting change, net of tax |
|
— |
|
(0.06 |
) |
(0.09 |
) |
|||
|
Net Income |
|
$ |
4.44 |
|
$ |
2.68 |
|
$ |
2.41 |
|
See notes to consolidated financial statements.
55
EQUITABLE RESOURCES, INC. AND
SUBSIDIARIES
STATEMENTS OF CONSOLIDATED
CASH FLOWS
YEARS ENDED DECEMBER 31,
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
$ |
279,854 |
|
$ |
173,557 |
|
$ |
150,626 |
|
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|||
|
Provision for losses on accounts receivable |
|
19,390 |
|
13,697 |
|
8,564 |
|
|||
|
Depreciation, depletion and amortization |
|
83,063 |
|
78,138 |
|
69,448 |
|
|||
|
Gain on exchange of Westport for Kerr-McGee shares |
|
(217,212 |
) |
— |
|
— |
|
|||
|
Impairment of assets |
|
39,590 |
|
11,059 |
|
5,320 |
|
|||
|
Charitable foundation contribution |
|
18,226 |
|
9,279 |
|
— |
|
|||
|
Amortization of construction contract costs |
|
1,675 |
|
1,680 |
|
3,581 |
|
|||
|
Recognition of prepaid forward production revenue |
|
(10,363 |
) |
(55,705 |
) |
(55,705 |
) |
|||
|
Amendment of prepaid forward contract |
|
(36,792 |
) |
— |
|
— |
|
|||
|
Loss on amendment of prepaid forward contract |
|
5,532 |
|
— |
|
— |
|
|||
|
Deferred income taxes |
|
111,773 |
|
69,084 |
|
42,869 |
|
|||
|
Change in undistributed earnings from nonconsolidated investments |
|
(2,008 |
) |
(6,664 |
) |
3,463 |
|
|||
|
Minority interest |
|
976 |
|
1,413 |
|
7,103 |
|
|||
|
Gain on sale of available-for-sale securities |
|
(3,024 |
) |
(13,985 |
) |
— |
|
|||
|
Changes in other assets and liabilities: |
|
|
|
|
|
|
|
|||
|
Accounts receivable and unbilled revenues |
|
(101,099 |
) |
(28,588 |
) |
(89,860 |
) |
|||
|
Inventory |
|
(45,283 |
) |
(84,738 |
) |
21,710 |
|
|||
|
Prepaid expenses and other |
|
(15,747 |
) |
(8,883 |
) |
12,938 |
|
|||
|
Regulatory assets |
|
506 |
|
11,897 |
|
614 |
|
|||
|
Accounts payable |
|
41,833 |
|
9,741 |
|
34,824 |
|
|||
|
Deferred income taxes |
|
29,378 |
|
(4,800 |
) |
6,291 |
|
|||
|
Pension contribution |
|
— |
|
(51,840 |
) |
— |
|
|||
|
Other assets |
|
(2,704 |
) |
(4,971 |
) |
(2,823 |
) |
|||
|
Other liabilities |
|
(21,201 |
) |
1,659 |
|
(4,452 |
) |
|||
|
Total adjustments |
|
(103,491 |
) |
(52,527 |
) |
63,885 |
|
|||
|
Net cash provided by operating activities |
|
176,363 |
|
121,030 |
|
214,511 |
|
|||
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|||
|
Capital expenditures |
|
(202,351 |
) |
(221,499 |
) |
(218,494 |
) |
|||
|
Purchase of minority interest in Appalachian Basin Partners, L.P. |
|
— |
|
(44,200 |
) |
— |
|
|||
|
Investment in available-for-sale securities |
|
— |
|
— |
|
(17,592 |
) |
|||
|
Distributions from nonconsolidated investments |
|
1,572 |
|
2,031 |
|
3,970 |
|
|||
|
Proceeds from sale of Kerr-McGee shares |
|
42,880 |
|
— |
|
— |
|
|||
|
Proceeds from sale of Westport stock |
|
— |
|
38,419 |
|
— |
|
|||
|
Proceeds from sale of equity in nonconsolidated investments |
|
— |
|
4,363 |
|
— |
|
|||
|
Proceeds from sale of property |
|
— |
|
6,550 |
|
— |
|
|||
|
Restricted cash from oil-dominated field sale |
|
— |
|
— |
|
62,956 |
|
|||
|
Net cash used in investing activities |
|
(157,899 |
) |
(214,336 |
) |
(169,160 |
) |
|||
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|||
|
Dividends paid |
|
(89,364 |
) |
(60,419 |
) |
(41,809 |
) |
|||
|
Purchase of treasury stock |
|
(118,472 |
) |
(55,235 |
) |
(97,028 |
) |
|||
|
Proceeds from exercises under employee compensation plans |
|
26,776 |
|
39,155 |
|
28,485 |
|
|||
|
Loans against construction contracts |
|
50,395 |
|
45,524 |
|
23,215 |
|
|||
|
Proceeds from issuance of long-term debt |
|
— |
|
200,000 |
|
200,000 |
|
|||
|
Repayments and retirements of long-term debt |
|
(21,032 |
) |
(24,733 |
) |
(641 |
) |
|||
|
Redemption of Trust Preferred Capital Securities |
|
— |
|
(125,000 |
) |
— |
|
|||
|
Increase (decrease) in short-term loans |
|
95,899 |
|
93,600 |
|
(169,447 |
) |
|||
|
Net cash (used in) provided by financing activities |
|
(55,798 |
) |
112,892 |
|
(57,225 |
) |
|||
|
Net (decrease) increase in cash and cash equivalents |
|
(37,334 |
) |
19,586 |
|
(11,874 |
) |
|||
|
Cash and cash equivalents at beginning of year |
|
37,334 |
|
17,748 |
|
29,622 |
|
|||
|
Cash and cash equivalents at end of year |
|
$ |
— |
|
$ |
37,334 |
|
$ |
17,748 |
|
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|||
|
Interest (net of amount capitalized) |
|
$ |
49,656 |
|
$ |
47,212 |
|
$ |
40,154 |
|
|
Income taxes |
|
$ |
23,043 |
|
$ |
4,661 |
|
$ |
18,941 |
|
See notes to consolidated financial statements.
56
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
|
|
|
2004 |
|
2003 |
|
||
|
|
|
(Thousands) |
|
||||
|
Assets |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Current assets: |
|
|
|
|
|
||
|
Cash and cash equivalents |
|
$ |
— |
|
$ |
37,334 |
|
|
Accounts receivable (less accumulated
provision for |
|
238,560 |
|
176,574 |
|
||
|
Unbilled revenues |
|
149,060 |
|
129,758 |
|
||
|
Inventory |
|
204,585 |
|
162,090 |
|
||
|
Derivative commodity instruments, at fair value |
|
27,585 |
|
34,657 |
|
||
|
Prepaid expenses and other |
|
32,859 |
|
17,115 |
|
||
|
Total current assets |
|
652,649 |
|
557,528 |
|
||
|
Equity in nonconsolidated investments |
|
64,556 |
|
89,175 |
|
||
|
|
|
|
|
|
|
||
|
Property, plant and equipment: |
|
|
|
|
|
||
|
Equitable Utilities |
|
1,087,910 |
|
1,041,011 |
|
||
|
Equitable Supply |
|
1,868,199 |
|
1,733,466 |
|
||
|
NORESCO |
|
11,807 |
|
17,322 |
|
||
|
Total property, plant and equipment |
|
2,967,916 |
|
2,791,799 |
|
||
|
Less: accumulated depreciation and depletion |
|
1,088,129 |
|
1,025,017 |
|
||
|
Net property, plant and equipment |
|
1,879,787 |
|
1,766,782 |
|
||
|
Investments, available-for-sale |
|
426,772 |
|
363,280 |
|
||
|
|
|
|
|
|
|
||
|
Other assets: |
|
|
|
|
|
||
|
Regulatory assets |
|
67,208 |
|
67,714 |
|
||
|
Goodwill |
|
51,656 |
|
51,656 |
|
||
|
Long-term receivables |
|
7,634 |
|
7,849 |
|
||
|
Other |
|
46,284 |
|
43,375 |
|
||
|
Total other assets |
|
172,782 |
|
170,594 |
|
||
|
Total |
|
$ |
3,196,546 |
|
$ |
2,947,359 |
|
See notes to consolidated financial statements.
57
EQUITABLE RESOURCES, INC. AND SUBSIDARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
|
|
|
2004 |
|
2003 |
|
||
|
|
|
(Thousands) |
|
||||
|
Liabilities and Common Stockholders’ Equity |
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
Current liabilities: |
|
|
|
|
|
||
|
Current portion of long-term debt |
|
$ |
10,582 |
|
$ |
21,267 |
|
|
Short-term loans |
|
295,499 |
|
199,600 |
|
||
|
Accounts payable |
|
187,797 |
|
146,086 |
|
||
|
Prepaid gas forward sale |
|
— |
|
20,840 |
|
||
|
Derivative commodity instruments, at fair value |
|
350,382 |
|
137,636 |
|
||
|
Current portion of project financing obligations |
|
31,329 |
|
56,368 |
|
||
|
Other current liabilities |
|
139,728 |
|
128,497 |
|
||
|
Total current liabilities |
|
1,015,317 |
|
710,294 |
|
||
|
|
|
|
|
|
|
||
|
Long-term debt: |
|
|
|
|
|
||
|
Debentures and medium-term notes |
|
617,769 |
|
632,147 |
|
||
|
Total long-term debt |
|
617,769 |
|
632,147 |
|
||
|
|
|
|
|
|
|
||
|
Deferred and other credits: |
|
|
|
|
|
||
|
Deferred income taxes |
|
486,241 |
|
459,877 |
|
||
|
Deferred investment tax credits |
|
11,037 |
|
12,125 |
|
||
|
Prepaid gas forward sale |
|
— |
|
20,783 |
|
||
|
Project financing obligations |
|
73,281 |
|
48,972 |
|
||
|
Other credits |
|
118,229 |
|
97,821 |
|
||
|
Total deferred and other credits |
|
688,788 |
|
639,578 |
|
||
|
|
|
|
|
|
|
||
|
Common stockholders’ equity: |
|
|
|
|
|
||
|
Common stock, no par value, authorized 160,000 shares; shares issued: 2004 and 2003, 74,504 |
|
356,892 |
|
348,133 |
|
||
|
Treasury stock, shares at cost: 2004, 13,473; 2003, 12,137; (net of shares and cost held in trust for deferred compensation of 642, $12,303 and 636, $12,111) |
|
(389,450 |
) |
(295,145 |
) |
||
|
Retained earnings |
|
1,087,577 |
|
897,087 |
|
||
|
Accumulated other comprehensive (loss) income |
|
(180,347 |
) |
15,265 |
|
||
|
Total common stockholders’ equity |
|
874,672 |
|
965,340 |
|
||
|
Total |
|
$ |
3,196,546 |
|
$ |
2,947,359 |
|
See notes to consolidated financial statements.
58
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF COMMON
STOCKHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31, 2004, 2003, AND 2002
|
|
|
Common Stock |
|
|
|
Accumulated |
|
Common |
|
||||||
|
|
|
Shares |
|
No |
|
Retained |
|
Comprehensive |
|
Stockholders’ |
|
||||
|
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
||||
|
Balance, December 31, 2001 |
|
63,870 |
|
$ |
79,567 |
|
$ |
675,207 |
|
$ |
91,380 |
|
$ |
846,154 |
|
|
Comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net income |
|
|
|
|
|
154,107 |
|
|
|
154,107 |
|
||||
|
Net change in cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Natural gas, net of tax benefit of $53,672 (see Note 3) |
|
|
|
|
|
|
|
(99,678 |
) |
(99,678 |
) |
||||
|
Interest rate |
|
|
|
|
|
|
|
(1,150 |
) |
(1,150 |
) |
||||
|
Unrealized loss on available-for-sale securities |
|
|
|
|
|
|
|
(1,494 |
) |
(1,494 |
) |
||||
|
Minimum pension liability adjustment, net of tax benefit of $6,744 |
|
|
|
|
|
|
|
(13,591 |
) |
(13,591 |
) |
||||
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
38,194 |
|
||||
|
Dividends ($0.67 per share) |
|
|
|
|
|
(41,809 |
) |
|
|
(41,809 |
) |
||||
|
Stock-based compensation plans, net |
|
1,378 |
|
33,128 |
|
|
|
|
|
33,128 |
|
||||
|
Stock repurchases |
|
(2,906 |
) |
(97,028 |
) |
|
|
|
|
(97,028 |
) |
||||
|
Balance, December 31, 2002 |
|
62,342 |
|
15,667 |
|
787,505 |
|
(24,533 |
) |
778,639 |
|
||||
|
Comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net income |
|
|
|
|
|
170,001 |
|
|
|
170,001 |
|
||||
|
Net change in cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Natural gas, net of tax benefit of $38,674 (see Note 3) |
|
|
|
|
|
|
|
(61,140 |
) |
(61,140 |
) |
||||
|
Interest rate |
|
|
|
|
|
|
|
(133 |
) |
(133 |
) |
||||
|
Unrealized gain on available-for-sale securities: |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Westport (a) |
|
|
|
|
|
|
|
99,630 |
|
99,630 |
|
||||
|
Other |
|
|
|
|
|
|
|
2,310 |
|
2,310 |
|
||||
|
Minimum pension liability adjustment, net of tax benefit of $448 |
|
|
|
|
|
|
|
(869 |
) |
(869 |
) |
||||
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
209,799 |
|
||||
|
Westport cost basis adjustment (a) |
|
|
|
52,857 |
|
|
|
|
|
52,857 |
|
||||
|
Dividends ($0.97 per share) |
|
|
|
|
|
(60,419 |
) |
|
|
(60,419 |
) |
||||
|
Stock-based compensation plans, net |
|
1,456 |
|
39,699 |
|
|
|
|
|
39,699 |
|
||||
|
Stock repurchases |
|
(1,432 |
) |
(55,235 |
) |
|
|
|
|
(55,235 |
) |
||||
|
Balance, December 31, 2003 |
|
62,366 |
|
52,988 |
|
897,087 |
|
15,265 |
|
965,340 |
|
||||
|
Comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net income |
|
|
|
|
|
279,854 |
|
|
|
279,854 |
|
||||
|
Net change in cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Natural gas, net of tax benefit of $82,277 (see Note 3) |
|
|
|
|
|
|
|
(138,926 |
) |
(138,926 |
) |
||||
|
Interest rate |
|
|
|
|
|
|
|
397 |
|
397 |
|
||||
|
Gain on exchange of Westport stock |
|
|
|
|
|
|
|
(143,360 |
) |
(143,360 |
) |
||||
|
Unrealized gain on available-for-sale securities: |
|
|
|
|
|
|
|
|
|
|
|
||||
|
Westport (to date of merger) |
|
|
|
|
|
|
|
43,731 |
|
43,731 |
|
||||
|
Kerr-McGee (from date of merger) |
|
|
|
|
|
|
|
36,334 |
|
36,334 |
|
||||
|
Other |
|
|
|
|
|
|
|
371 |
|
371 |
|
||||
|
Minimum pension liability adjustment, net of tax benefit of $3,009 |
|
|
|
|
|
|
|
5,841 |
|
5,841 |
|
||||
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
84,242 |
|
||||
|
Dividends ($1.44 per share) |
|
|
|
|
|
(89,364 |
) |
|
|
(89,364 |
) |
||||
|
Stock-based compensation plans, net |
|
1,015 |
|
32,926 |
|
|
|
|
|
32,926 |
|
||||
|
Stock repurchases |
|
(2,350 |
) |
(118,472 |
) |
|
|
|
|
(118,472 |
) |
||||
|
Balance, December 31, 2004 |
|
61,031 |
|
$ |
(32,558 |
) |
$ |
1,087,577 |
|
$ |
(180,347 |
) |
$ |
874,672 |
|
Common shares authorized: 160,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding.
(a) Includes a reclassification of $52.9 million to common stock for the change in accounting treatment of the Company’s investment in Westport from the equity method to available-for-sale, effective March 31, 2003. The Westport shares were subsequently exchanged during 2004 for Kerr-McGee shares (see Note 10). Except for those described in Note 3, there were no other reclassification adjustments for any other categories in 2004, 2003 and 2002.
See notes to consolidated financial statements.
59
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
DECEMBER 31, 2004
1. Summary of Significant Accounting Policies
Principles of Consolidation: The consolidated financial statements include the accounts of Equitable Resources, Inc. and all subsidiaries, ventures and partnerships in which a controlling equity interest is held (Equitable or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. Equitable, in most instances, utilizes the equity method of accounting for companies where its ownership is less than or equal to 50% and significant influence exists.
Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest charges.
Inventories: The Company’s inventory balance consists of natural gas stored underground and materials and supplies. The amount of natural gas stored underground that is not related to the Company’s energy trading activities plus the amount of materials and supplies are recorded at the lower of average cost or market. The amount of natural gas stored underground that was purchased on or before October 25, 2002 and that relates to energy trading activities was recorded at fair value in accordance with the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) No. 98-10, “Accounting for Contracts Involved in Energy and Risk Management Activities” (EITF No. 98-10). Subsequent to October 25, 2002, the Company has recorded the purchase of the physical inventory associated with its energy trading activities at the lower of cost or market in accordance with EITF No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17” (EITF No. 02-3), which rescinded the guidance contained in EITF No. 98-10.
Properties, Plant and Equipment: The Company’s properties, plant and equipment consists of the following:
|
|
|
December 31, |
|
||||
|
|
|
2004 |
|
2003 |
|
||
|
|
|
(Thousands) |
|
||||
|
Utility plant |
|
$ |
1,085,476 |
|
$ |
1,038,586 |
|
|
Accumulated depreciation and amortization |
|
366,124 |
|
349,129 |
|
||
|
Net utility plant |
|
719,352 |
|
689,457 |
|
||
|
Gas and oil producing properties, successful efforts method |
|
1,396,898 |
|
1,303,655 |
|
||
|
Accumulated depletion |
|
488,742 |
|
450,761 |
|
||
|
Net oil and gas producing properties |
|
908,156 |
|
852,894 |
|
||
|
Other properties, at cost less accumulated depreciation |
|
252,279 |
|
224,431 |
|
||
|
Net property, plant and equipment |
|
$ |
1,879,787 |
|
$ |
1,766,782 |
|
Utility property, plant and equipment, principally regulated property, is carried at cost. Depreciation is recorded using composite rates on a straight-line basis. The overall rate of depreciation for the years ended December 31, 2004 and December 31, 2003 was approximately 4% of net Utility properties.
Oil and gas producing properties use the successful efforts method of accounting for production activities. The majority of this line item consists of gas producing properties which were depleted at a rate of $0.54/mcf and $0.49/mcf produced for the years ended December 31, 2004 and December 31, 2003, respectively.
60
The Company also had $252.3 million and $224.4 million of other net property at December 31, 2004 and December 31, 2003 respectively. These items are carried at cost and depreciation is calculated using the straight-line method based on estimated service lives. This property consists largely of gathering systems (25 year estimated service life), buildings (35 year estimated service life), office equipment (3-7 year estimated service life), vehicles (5 year estimated service life), and computer and telecommunications equipment and systems (3-7 year estimated service life).
Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized.
Oil & Gas Properties: The Company uses the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. The depletion is calculated based on the annual actual production multiplied by the depletion rate per unit. The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. Equitable Supply calculates a single depletion field including all reserves located in Kentucky, West Virginia, Virginia, Ohio and Pennsylvania. Costs of exploratory dry holes, geological and geophysical, delay rentals, and other property carrying costs are charged to expense.
The carrying value of the Company’s proved oil and gas properties are reviewed for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, Equitable estimates the expected future cash flows (on an undiscounted basis) from the Company’s proved oil and gas properties and compares them to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves utilizing assumptions about the use of the asset and forward market prices for oil and gas. Proved oil and gas properties that have carrying amounts in excess of undiscounted future cash flows are deemed unrecoverable. Those properties are then written down to fair value, which is estimated using assumptions that marketplace participants would use in their estimates of fair value. In developing estimates of fair value, the Company used forward market prices. For the years ended December 31, 2004, 2003, and 2002 the Company did not recognize impairment charges on oil and gas properties.
Additionally, the costs of unproved oil and gas properties are periodically assessed on a field-by-field basis. If unproved properties are determined to be productive, the related costs are transferred to proved oil and gas properties. If unproved properties are determined not to be productive, or if the value has been otherwise impaired, the excess carrying value is charged to expense. For additional information on oil and gas properties, see Note 27 (unaudited).
Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves from the depletion pool unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds.
Regulatory Accounting: The Company’s distribution operations are subject to comprehensive regulation by the Pennsylvania Public Utilities Commission (PA PUC) and the Public Service Commission of West Virginia. The Company also provides field line service (also referred to as “farm tap” service as the customer is served directly from a well or gathering pipeline) in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. The Company’s interstate pipeline operations are subject to regulation by the Federal Energy Regulatory Commission (FERC). Accounting for the Company’s regulated operations is performed in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” The application of this accounting policy allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities 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 Statements of Consolidated Income for a non-regulated company. The deferred regulatory
61
assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.
Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, the Company defers the difference between its purchased natural gas cost, less refunds, and the billing of such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Company’s Consolidated Balance Sheets as other current assets or liabilities.
When any portion of the Company’s distribution or pipeline operations cease to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurred.
The following table presents the total regulated net revenue and operating expenses of the Company:
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Distribution revenues |
|
$ |
422,438 |
|
$ |
396,203 |
|
$ |
330,865 |
|
|
Pipeline revenues |
|
55,123 |
|
52,926 |
|
56,742 |
|
|||
|
Total regulated revenue |
|
477,561 |
|
449,129 |
|
387,607 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Distribution purchased gas costs |
|
263,313 |
|
231,017 |
|
174,772 |
|
|||
|
Pipeline purchased gas costs |
|
— |
|
— |
|
67 |
|
|||
|
Total purchased gas costs |
|
263,313 |
|
231,017 |
|
174,839 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Distribution net revenue |
|
159,125 |
|
165,186 |
|
156,093 |
|
|||
|
Pipeline net revenue |
|
55,123 |
|
52,926 |
|
56,675 |
|
|||
|
Total regulated net revenue |
|
214,248 |
|
218,112 |
|
212,768 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Distribution operating expenses |
|
102,248 |
|
102,093 |
|
96,072 |
|
|||
|
Pipeline operating expenses |
|
30,467 |
|
30,511 |
|
31,297 |
|
|||
|
Total regulated operating expenses |
|
$ |
132,715 |
|
$ |
132,604 |
|
$ |
127,369 |
|
Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC). The CRC reports to the Audit Committee of the Board of Directors and is comprised of the chief executive officer, the chief financial officer and other officers and employees.
The Company’s risk management program includes the use of (i) exchange-traded natural gas futures contracts and options and over-the-counter (OTC) natural gas swap agreements and options (collectively, derivative contracts) to hedge exposures to fluctuations in natural gas prices and for trading purposes, (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates, and (iii) variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee Corporation (Kerr-McGee) shares through the use of collars by effectively purchasing a put option from and selling a call option to a counterparty. At contract inception, the Company designates its derivative instruments as hedging or trading activities.
All derivative instruments are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (Statement No. 133) as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of Financial Accounting Standards Board Statement No. 133” (Statement No. 137), SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement No. 138), and by SFAS No. 149, “Amendment of Statement 133 on
62
Derivative Instruments and Hedging Activities” (Statement No. 149). As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, hedge ineffectiveness is recorded. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed appropriate by the Company’s CRC. The Company assesses the effectiveness of hedging relationships both at the inception of the hedge and on an on-going basis.
The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income, net of tax, and is subsequently reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. If a cash flow hedge is terminated before the settlement date of the hedged item, the amount of accumulated other comprehensive income recorded up to that date would remain accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument would be recorded in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income have been designated and qualify as cash flow hedges.
The Company reports all gains and losses on its energy trading contracts net on its Statements of Consolidated Income in accordance with Emerging Issues Task Force (EITF) No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17” (EITF No. 02-3). The variable share forward contracts meet the requirements of SFAS No. 133 Implementation Issue G20, “Assessing and Measuring the Effectiveness of an Option used in a Cash Flow Hedge,” and have been designated as cash flow hedges. Under this guidance, perfect hedge effectiveness is assumed and the entire fair value of the collar is recorded in other comprehensive income.
Capitalized Interest: Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. Interest costs during 2004, 2003 and 2002 of $0.4 million, $0.8 million and $1.4 million, respectively, were capitalized as a portion of the cost of the related long-term assets.
Goodwill: Goodwill is the excess of the acquisition cost of businesses over the fair value of the identifiable net assets (tangible and intangible) acquired. Goodwill was required to be evaluated for impairment at the beginning of 2002 and on an annual basis thereafter according to SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement No. 142). The Statement requires that a two-step process be performed to analyze whether or not goodwill has been impaired. Step one requires that the fair value be compared to book value. If the fair value is higher than the book value, no impairment is indicated and there is no need to perform the second step of the process. If the fair value is lower than the book value, step two must be evaluated. Step two requires that a hypothetical purchase price allocation analysis be done to reflect a current book value of goodwill. This current value is then compared to the carrying value of goodwill. If the current fair value is lower than the carrying value, an impairment must be recorded. Annually, the goodwill is tested for impairment in the fourth quarter.
Impairment of Long-Lived Assets: In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement No. 144), whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.
63
During the second quarter 2002, the Company reviewed the Jamaica power plant project related to the NORESCO operating segment for impairment as the project had not been operating to expected levels in order to meet anticipated profit goals and remediation efforts were unsuccessful. The Company owned 91.2% of the equity in the project and therefore had consolidated the project in its financial statements until the adoption of FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN No. 46) effective July 1, 2003. As a result of the Company’s review, an impairment loss of $5.3 million was recorded to adjust the project assets to their fair value. Fair value was based on the expected future cash flows to be generated by the Jamaican power plant, discounted at the risk-free rate of interest.
Stock-Based Compensation: The Company accounts for its stock options and awards under the intrinsic-value-based method as defined in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Accordingly, no compensation cost for fixed stock options is included in net income since all awards were made at the fair value on the date of grant. Compensation expense for restricted share awards is ratably recognized over the vesting period, based on the fair value of the stock on the date of grant. The Company applies the disclosure provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (Statement No. 123) and SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure an amendment of FASB Statement No. 123” (Statement No. 148).
The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement No. 123 to employee share-based awards. Refer to Note 19 for more information regarding share-based compensation.
|
|
|
Year Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Net Income, as reported |
|
$ |
279,854 |
|
$ |
170,001 |
|
$ |
154,107 |
|
|
Add: Share-based employee compensation expense included in reported net income, net of related tax effects |
|
20,374 |
|
11,879 |
|
5,975 |
|
|||
|
Deduct: Total share-based employee compensation expense determined under fair value method for all awards, net of related tax effects |
|
(24,575 |
) |
(18,015 |
) |
(12,910 |
) |
|||
|
Pro Forma net income |
|
$ |
275,653 |
|
$ |
163,865 |
|
$ |
147,172 |
|
|
Earnings per share: |
|
|
|
|
|
|
|
|||
|
Basic, as reported |
|
$ |
4.54 |
|
$ |
2.74 |
|
$ |
2.45 |
|
|
Basic, pro forma |
|
$ |
4.47 |
|
$ |
2.64 |
|
$ |
2.34 |
|
|
|
|
|
|
|
|
|
|
|||
|
Diluted, as reported |
|
$ |
4.44 |
|
$ |
2.68 |
|
$ |
2.41 |
|
|
Diluted, pro forma |
|
$ |
4.37 |
|
$ |
2.58 |
|
$ |
2.30 |
|
Revenue Recognition: Sales of natural gas to utility customers are billed on a monthly cycle basis; however, the billing cycle periods for certain customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for utility segment revenue whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. Revenue is recognized for production activities when deliveries of natural gas, crude oil and natural gas liquids are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Revenues from energy marketing activities are recognized when deliveries occur. In accordance with EITF No. 02-3, only revenues associated with energy trading activities that do not result in physical delivery of an energy commodity (i.e. are settled in cash) are recorded in accordance with mark to market accounting. The revenues associated with the physical delivery of an energy commodity are recognized at contract value when delivered. Revenues associated with the Company’s natural gas advance sales contracts are recognized as natural gas is gathered and delivered.
64
The NORESCO segment recognizes revenue and profit from long-term contracts, including turnkey energy savings performance contracts, using the percentage of completion method of accounting. The percentage of completion method measures the percentage of contract costs incurred to date to the estimated total contract costs for each contract. Contract costs include all direct material, labor, subcontract costs and those indirect costs related to contract performance. Revenue from contract change orders and claims is recognized when settlement is probable and the amount can be reasonably estimated. Costs and estimated profits in excess of billings are classified as a current asset. Amounts billed in excess of costs and estimated profits are classified as a current liability. NORESCO follows this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. However, due to uncertainties inherent in the estimation process, actual results could differ from those estimates. Since the financial reporting of these contracts depends on estimates, which are assessed continually during the term of the contract, recognized revenues and profit are subject to revisions as the contract progresses to completion. The revenue recognized on contracts is not related to progress billings to customers. Revisions in profit estimates are reflected in the period in which the facts that give rise to the revision become known. Accordingly, favorable changes in estimates result in additional profit recognition, and unfavorable changes in estimates result in the reduction of previously recognized revenue and profits. The accuracy of the gross margins the Company reports for contracts is dependent upon various judgments it makes with respect to its contract performance, its cost estimates, and its ability to recover additional contract costs through change orders or claims. When estimates indicate a loss under a contract, cost of sales is charged with a provision for such loss in the period in which such losses are identified. As work progresses under a loss contract, revenues continue to be recognized, and a portion of the contract costs incurred in each period is charged to the contract loss reserve. The Company had no loss contracts as of December 31, 2004.
Balances billed but not paid by customers under retainage provisions in contracts were not significant at December 31, 2004. There were no significant amounts representing sales value of performance that had not been billed and were not billable to customers at December 31, 2004. There were no unbilled amounts representing claims or other similar items subject to uncertainty concerning their determination or ultimate realization that would be considered material enough for disclosure at December 31, 2004.
With certain projects, the Company enters into shared energy savings contracts to provide sustained levels of energy savings to its customers. The terms of the project are defined by an energy services agreement between the Company and the customer. Once completed, these projects will earn revenue from the customer based on the measurement formulas established in the energy services agreement. The Company recognizes revenue from shared energy savings contracts as energy savings are measured and verified, in accordance with the established measurement formulas.
Revenue received from customer contract termination payments is recognized when received. Any maintenance revenues are recognized as related services are performed.
Sales of Receivables: The Company, through its NORESCO segment, enters into construction contracts with governmental and institutional counterparties whereby those counterparties finance the construction directly with the Company at prevailing market interest rates. In order to accelerate cash collections and manage working requirements, the Company transfers these contract receivables due from customers to financial institutions. The transfer price of the contract receivables is based on the face value of the executed contract with the financial institution. The gain or loss on the sale of contract receivables is the difference between the existing carrying amount of the financial assets involved in the transfer and the transfer price of the contract with the financial institution.
Certain of these transfers do not immediately qualify as “sales” under SFAS No. 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (Statement No. 140). For the contract receivables that are transferred and still controlled by the Company, a liability is established to offset the cash received from the transfer. This liability is recognized until control has been surrendered in accordance with Statement No. 140, as the cash received by the Company can be called by the financial institution at the time it is determined that control will not be surrendered. The Company de-recognizes the receivables and the liabilities when control has been surrendered in accordance with the criteria provided in Statement No. 140. The Company does not retain any interests in the contract receivables once the sale is complete. As of December 31, 2004, the
65
Company had recorded a current liability of $31.3 million classified as current portion of project financing obligations and a long-term liability of $73.3 million classified as project financing obligations on the Consolidated Balance Sheets. The current portion of project financing obligations represents transfers for which control is expected to be surrendered, and cash could be called, within one year. The related assets are classified as unbilled revenues as construction progresses and as other assets upon completion of construction.
For the year ended December 31, 2004, approximately $53.8 million of the contract receivables met the criteria for sales treatment generating a recognized gain of $1.2 million. The de-recognition of the $53.8 million in receivables and the related liabilities was a non-cash transaction and is consequently not reflected in the Statements of Consolidated Cash Flows.
Investments: Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets.
Accounting Principles Board No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB No. 18), requires a company to recognize a loss in the value of an equity method investment that is other than a temporary decline. The Company analyzes its equity method investments based on its share of estimated future cash flows from the investment to determine whether the carrying amount will be recoverable.
Other investments in equity securities which are generally under 20% ownership and where the Company does not exert significant influence over operating and financial polices are accounted for as available-for-sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (Statement No. 115). These investments are classified as investments, available-for-sale on the Consolidated Balance Sheets.
The Company has evaluated its investment policy in accordance with Statement No. 115 and has determined that all of its investment securities are appropriately classified as available-for-sale. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheets within a separate component of equity, accumulated other comprehensive income. The Company utilizes the specific identification method to determine the cost of the securities sold.
In accordance with Statement No. 115, the Company continually reviews its available-for-sale investments to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the Statements of Consolidated Income. No other than temporary decline in fair value was recorded in 2004 or 2003.
Income Taxes: The Company files a consolidated Federal income tax return. The Company utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate effective income tax rates are calculated for income from continuing operations, discontinued operations and cumulative effects of accounting changes.
Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities in accordance with SFAS No. 109, “Accounting for Income Taxes” (Statement No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of such temporary differences. The statement also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.
66
Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.
Allowance for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the credit-worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense on the Statements of Consolidated Income. The reserve is based on historical experience, current and expected economic trends, and specific information about customer accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.
Earnings Per Share (EPS): Basic EPS is computed by dividing net income by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing net income adjusted for the assumed conversion of debt, by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and awards. See Note 17 for a detailed calculation.
Segment Disclosures: Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief executive officer (chief operating decision maker) in deciding how to allocate resources. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity earnings from nonconsolidated investments, excluding Westport Resources Corporation (Westport), minority interest, and other income, net. Interest expenses and income taxes are managed on a consolidated basis. Headquarter costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.
Asset Retirement Obligations: In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement No. 143). Statement No. 143 was adopted by the Company effective January 1, 2003, and its primary impact was to change the method of accruing for well plugging and abandonment costs. These costs were formerly recognized as a component of depreciation, depletion and amortization (DD&A) expense with a corresponding credit to accumulated depletion in accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (Statement No. 19). At the end of 2002, the cumulative credit included within accumulated depletion totaled approximately $20.9 million. Statement No. 143 requires that the fair value of the Company’s plugging and abandonment obligations be recorded at the time the obligations are incurred, which is typically at the time the wells are drilled. Upon initial recognition of an asset retirement obligation, the Company will increase the carrying amount of the long-lived asset by the same amount as the liability. Over time the liabilities are accreted for the change in their present value, through charges to DD&A, and the initial capitalized costs are depleted over the useful lives of the related assets.
The adoption of Statement No. 143 by the Company resulted in an after-tax charge to earnings of $3.6 million, or $0.06 per diluted share, which is reflected as a cumulative effect of accounting change in the Company’s Statement of Consolidated Income for the year ended December 31, 2003. In addition to the charge to earnings, the depletion rate in the Company’s Supply segment increased by $0.03 per Mcfe. The Company also recognized a $28.7 million other long-term liability and a $2.3 million long-term asset upon adoption of Statement No. 143. The long-term obligation represents the net present value of the estimated future expenditures required to plug and abandon the Company’s approximately 12,600 wells in the Appalachian Basin, significant portions of which are not projected to occur for over 40 years.
67
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations. The Company does not have any assets that are legally restricted for purposes of settling these obligations.
|
|
|
Year ended |
|
|
|
|
|
December 31, |
|
|
|
|
|
(Thousands) |
|
|
|
Asset retirement obligation as of beginning of period |
|
$ |
29,780 |
|
|
Accretion expense |
|
1,963 |
|
|
|
Liabilities incurred |
|
604 |
|
|
|
Liabilities settled |
|
(490 |
) |
|
|
Asset retirement obligation as of end of period |
|
$ |
31,857 |
|
Assuming retroactive application of the change in accounting principle as of January 1, 2002, the pro forma effect of applying this new accounting principle on a retroactive basis would not materially change reported net income for the year ended December 31, 2002.
Self Insurance: The Company is self-insured for certain losses related to workers’ compensation. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly, and by independent actuaries annually, to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from estimates.
Recently Issued Accounting Standards: In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN No. 46). FIN No. 46 required certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity did not have the characteristics of a controlling financial interest or did not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Prior to FIN No. 46, an entity was generally consolidated by an enterprise when the enterprise had a controlling financial interest through ownership of a majority voting interest in the entity. FIN No. 46 was effective for all new variable interest entities created or acquired after January 31, 2003. The Company adopted FIN No. 46 for variable interest entities created or acquired prior to February 1, 2003 as of July 1, 2003. The adoption of FIN No. 46 required the consolidation of Plymouth Cogeneration Limited Partnership (Plymouth), a joint venture entered into by NORESCO, and the deconsolidation of EAL/ERI Cogeneration Partners LP (Jamaica), which is the partnership that holds the Jamaican power plant.
In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R) that modified some of the provisions of FIN No. 46 and provided exemptions to certain entities from the original guidance. The Company adopted FIN No. 46R in the first quarter of 2004. The adoption of FIN No. 46R required the Company to deconsolidate Plymouth as of January 1, 2004, due to certain modifications of the original FIN No. 46 provisions.
This deconsolidation returned Plymouth to the equity method of accounting for investments. The Company restored the equity investment in Plymouth of $0.1 million and decreased minority interest by $0.6 million in the Consolidated Balance Sheet. As of January 1, 2004, $4.9 million of assets and $4.9 million of liabilities, including nonrecourse debt of $4.0 million, were removed from the Consolidated Balance Sheet.
The Company also has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which Equitable was not deemed to be the primary beneficiary. As of December 31, 2004, ANPI had $255.5 million of total assets and $312.6 million of total liabilities (including $172.9 million of long-term debt, including current maturities), excluding minority interest. The Company’s maximum exposure to a loss as a result of its involvement with ANPI is estimated to be approximately $29 million.
68
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R). This guidance replaced previously-existing requirements under SFAS 123, “Accounting for Stock-Based Compensation” (Statement No. 123), and APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Statement No. 123R eliminates the ability for an entity to account for share-based compensation transactions using the intrinsic value method of APB No. 25. Under Statement No. 123R, an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award would generally be measured based on the grant-date fair value of the award. Statement No. 123R will be effective for public entities in the first interim or annual period beginning after June 15, 2005. While the impact of adoption of Statement No. 123R cannot be determined at this time, the Company will continue to evaluate the impact of this guidance on the Company’s financial position and results of operations. Had the Company adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share also disclosed in Note 1.
On June 17, 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” The proposed interpretation would clarify that a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A recording of the liability at fair value would be recognized for a conditional asset retirement obligation when the liability is incurred. Certain factors regarding the timing and method of the settlement, which are conditional upon the future events occurring, would be factored into the measurement of the liability rather than the recognition of the liability. The final rules are expected to be issued in early 2005 and are anticipated to be effective no later than the end of the fiscal year ending after December 15, 2005. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final rules are issued.
Reclassification: Certain previously reported amounts have been reclassified to conform to the 2004 presentation. These reclassifications did not affect reported net income.
2. Financial Information by Business Segment
The Company reports its operations in three segments, which reflect its lines of business. The Equitable Utilities segment’s operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities. The Equitable Supply segment’s activities comprise the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil, and the extraction and sale of natural gas liquids. The NORESCO segment’s activities comprise an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency, including performance contracting, energy efficiency programs, combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation.
Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity earnings from nonconsolidated investments, excluding Westport, minority interest, and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.
Substantially all of the Company’s operating revenues, income from continuing operations and assets are generated or located in the United States.
69
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Revenues from external customers: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities |
|
$ |
731,861 |
|
$ |
613,368 |
|
$ |
754,273 |
|
|
Equitable Supply |
|
390,428 |
|
332,434 |
|
288,992 |
|
|||
|
NORESCO |
|
146,426 |
|
170,703 |
|
190,107 |
|
|||
|
Less: intersegment revenues (a) |
|
(77,106 |
) |
(69,228 |
) |
(164,304 |
) |
|||
|
Total |
|
$ |
1,191,609 |
|
$ |
1,047,277 |
|
$ |
1,069,068 |
|
|
Total operating expenses: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities |
|
$ |
134,556 |
|
$ |
135,244 |
|
$ |
131,478 |
|
|
Equitable Supply |
|
163,059 |
|
136,639 |
|
117,790 |
|
|||
|
NORESCO |
|
24,390 |
|
24,083 |
|
30,459 |
|
|||
|
Unallocated expenses (b) |
|
45,813 |
|
20,388 |
|
5,407 |
|
|||
|
Total |
|
$ |
367,818 |
|
$ |
316,354 |
|
$ |
285,134 |
|
|
Operating income: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities |
|
$ |
108,149 |
|
$ |
109,879 |
|
$ |
101,929 |
|
|
Equitable Supply |
|
227,369 |
|
195,795 |
|
171,202 |
|
|||
|
NORESCO |
|
14,946 |
|
16,931 |
|
9,847 |
|
|||
|
Unallocated expenses (b) |
|
(45,813 |
) |
(20,388 |
) |
(5,407 |
) |
|||
|
Total operating income |
|
$ |
304,651 |
|
$ |
302,217 |
|
$ |
277,571 |
|
|
|
|
|
|
|
|
|
|
|||
|
Reconciliation of operating income to net income: |
|
|
|
|
|
|
|
|||
|
Equity (losses) earnings from nonconsolidated investments, excluding Westport: |
|
|
|
|
|
|
|
|||
|
Equitable Supply |
|
$ |
688 |
|
$ |
431 |
|
$ |
282 |
|
|
NORESCO (c) |
|
(38,438 |
) |
(8,589 |
) |
4,699 |
|
|||
|
Unallocated earnings |
|
168 |
|
149 |
|
32 |
|
|||
|
Total |
|
$ |
(37,582 |
) |
$ |
(8,009 |
) |
$ |
5,013 |
|
|
Minority interest: |
|
|
|
|
|
|
|
|||
|
Equitable Supply |
|
$ |
— |
|
$ |
(871 |
) |
$ |
(7,103 |
) |
|
NORESCO |
|
(976 |
) |
(542 |
) |
— |
|
|||
|
Total |
|
$ |
(976 |
) |
$ |
(1,413 |
) |
$ |
(7,103 |
) |
|
Other income, net: |
|
|
|
|
|
|
|
|||
|
Equitable Supply |
|
$ |
576 |
|
$ |
— |
|
$ |
— |
|
|
Unallocated (d) |
|
3,116 |
|
— |
|
— |
|
|||
|
Total |
|
$ |
3,692 |
|
$ |
— |
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|||
|
Gain on exchange of Westport for Kerr-McGee shares |
|
217,212 |
|
— |
|
— |
|
|||
|
Charitable foundation contribution |
|
(18,226 |
) |
(9,279 |
) |
— |
|
|||
|
Gain on sale of available-for-sale securities |
|
3,024 |
|
13,985 |
|
— |
|
|||
|
Westport equity earnings (losses) |
|
— |
|
3,614 |
|
(8,476 |
) |
|||
|
Interest expense |
|
49,247 |
|
45,766 |
|
38,787 |
|
|||
|
Income tax expense |
|
142,694 |
|
81,792 |
|
77,592 |
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
279,854 |
|
173,557 |
|
150,626 |
|
|||
|
Income from discontinued operations |
|
— |
|
— |
|
9,000 |
|
|||
|
Cumulative effect of accounting change, net of tax (e) |
|
— |
|
(3,556 |
) |
(5,519 |
) |
|||
|
Net income |
|
$ |
279,854 |
|
$ |
170,001 |
|
$ |
154,107 |
|
70
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
|
|
(Thousands) |
|
|
|
|||
|
Significant noncash expense items: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities: |
|
|
|
|
|
|
|
|||
|
Increase (decrease) in deferred purchased natural gas cost |
|
$ |
13,270 |
|
$ |
3,553 |
|
$ |
(9,231 |
) |
|
Regulatory asset valuation allowance |
|
6,004 |
|
— |
|
— |
|
|||
|
NORESCO: |
|
|
|
|
|
|
|
|||
|
Impairment of long-lived assets |
|
— |
|
— |
|
5,320 |
|
|||
|
International investments, primarily impairment (c) |
|
39,590 |
|
11,059 |
|
— |
|
|||
|
Total |
|
$ |
58,864 |
|
$ |
14,612 |
|
$ |
(3,911 |
) |
|
|
|
|
|
|
|
|
|
|||
|
Segment assets: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities |
|
$ |
1,201,400 |
|
$ |
1,120,708 |
|
$ |
929,718 |
|
|
Equitable Supply |
|
1,514,176 |
|
1,338,702 |
|
1,079,924 |
|
|||
|
NORESCO (f) |
|
197,201 |
|
323,569 |
|
269,707 |
|
|||
|
Total operating segments |
|
2,912,777 |
|
2,782,979 |
|
2,279,349 |
|
|||
|
Headquarters assets, including cash and short-term investments |
|
283,769 |
|
164,380 |
|
157,542 |
|
|||
|
Total |
|
$ |
3,196,546 |
|
$ |
2,947,359 |
|
$ |
2,436,891 |
|
|
|
|
|
|
|
|
|
|
|||
|
Depreciation, depletion and amortization: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities |
|
$ |
25,629 |
|
$ |
27,583 |
|
$ |
26,894 |
|
|
Equitable Supply |
|
55,836 |
|
48,748 |
|
40,711 |
|
|||
|
NORESCO |
|
987 |
|
1,416 |
|
1,618 |
|
|||
|
Other |
|
611 |
|
391 |
|
225 |
|
|||
|
Total |
|
$ |
83,063 |
|
$ |
78,138 |
|
$ |
69,448 |
|
|
|
|
|
|
|
|
|
|
|||
|
Expenditures for segment assets: |
|
|
|
|
|
|
|
|||
|
Equitable Utilities |
|
$ |
56,274 |
|
$ |
60,414 |
|
$ |
70,188 |
|
|
Equitable Supply (g) |
|
141,661 |
|
204,527 |
|
147,461 |
|
|||
|
NORESCO |
|
538 |
|
307 |
|
698 |
|
|||
|
Other |
|
3,878 |
|
451 |
|
147 |
|
|||
|
Total |
|
$ |
202,351 |
|
$ |
265,699 |
|
$ |
218,494 |
|
(a) Intersegment revenues primarily represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.
(b) Unallocated expenses consist primarily of certain performance-related incentive costs and administrative costs that are not allocated to the operating segments. For the year ended December 31, 2004, unallocated expenses also include $13.4 million related to the settlement of the cash balance portion of a defined benefit pension plan as more fully discussed in Note 16.
(c) Equity losses from nonconsolidated investments include a $39.6 million impairment charge for the year ended December 31, 2004 and an $11.1 million impairment charge for the year ended December 31, 2003 related to NORESCO’s international investments. See Note 9 for further discussion.
(d) Unallocated other income, net for the year ended December 31, 2004 relates to pre-tax dividend income of $3.1 million recorded in the second half of 2004 relating to the Company’s 7.0 million Kerr-McGee shares.
(e) Net income for the years ended December 31, 2003 and December 31, 2002 has been adjusted to reflect the cumulative effect of an accounting change related to the adoption of Statement No. 143 and No. 142, respectively. See Note 1.
(f) The Company’s goodwill balance as of December 31, 2004, December 31, 2003 and December 31, 2002 totaled $51.7 million and is entirely related to the NORESCO segment. See Note 12.
(g) 2003 expenditures include $44.2 million for the acquisition of the remaining 31% limited partner interest in Appalachian Basin Partners, LP. See Note 5.
71
3. Derivative Instruments
The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities. OTC arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $26.8 million asset and a $350.4 million liability as of December 31, 2004, and a $34.5 million asset and a $137.6 million liability as of December 31, 2003. These amounts are classified in the Consolidated Balance Sheets as derivative commodity instruments, at fair value. The net amount of derivative commodity instruments, at fair value, changed from a net liability of $103.1 million at December 31, 2003 to a net liability of $323.6 million at December 31, 2004, primarily as a result of the increase in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 432.6 Bcf and 347.2 Bcf as of December 31, 2004 and 2003, respectively, and primarily relate to natural gas swaps. The open swaps at year-end 2004 have maturities extending through December 2011.
The Company deferred net losses of $197.3 million and $58.4 million in accumulated other comprehensive income, net of tax, as of December 31, 2004 and 2003, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $50.3 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss as of December 31, 2004 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions.
During the year ended December 31, 2004, the net change in accumulated other comprehensive income related to derivatives was a loss of $138.9 million, net of tax. This was comprised of a $43.6 million net realized loss which was reclassified from accumulated other comprehensive income to earnings and a net unrealized loss of $182.5 million. During the year ended December 31, 2003, the net change in accumulated other comprehensive income related to derivatives was a loss of $61.1 million, net of tax. This was comprised of a $28.8 million net realized loss which was reclassified from accumulated other comprehensive income to earnings and a net unrealized loss of $89.9 million. During the year ended December 31, 2002, the net change in accumulated other comprehensive income related to derivatives was a loss of $99.7 million, net of tax. This was comprised of a $14.5 million net realized loss which was reclassified from accumulated other comprehensive income to earnings and a net unrealized loss of $114.2 million.
For the years ended December 31, 2004, 2003 and 2002, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges (decreased) increased earnings by approximately $(2.0) million, $(2.9) million and $1.5 million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.
The Company conducts trading activities through its unregulated marketing group. The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy.
At December 31, 2004, the absolute notional quantities of the futures and swaps held for trading purposes totaled 6.2 Bcf and 46.8 Bcf, respectively.
72
Below is a summary of the activity of the fair value of the Company’s derivative contracts with third parties held for trading purposes during the year ended December 31, 2004 (in thousands).
|
Fair value of contracts outstanding as of December 31, 2003 |
|
$ |
173 |
|
|
Contracts realized or otherwise settled |
|
236 |
|
|
|
Other changes in fair value |
|
72 |
|
|
|
Fair value of contracts outstanding as of December 31, 2004 |
|
$ |
481 |
|
There were no adjustments to the fair value of the Company’s derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the years ended December 31, 2004 and 2003.
The following table presents the maturities and the fair valuation source for the Company’s derivative commodity instruments that were held for trading purposes as of December 31, 2004.
|
Source of Fair Value |
|
Maturity |
|
Maturity |
|
Maturity |
|
Maturity in |
|
Total Fair |
|
|||||
|
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
|||||
|
Prices actively quoted (NYMEX) (1) |
|
$ |
413 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
413 |
|
|
Prices provided by other external sources (2) |
|
19 |
|
38 |
|
11 |
|
— |
|
68 |
|
|||||
|
Net derivative assets |
|
$ |
432 |
|
$ |
38 |
|
$ |
11 |
|
$ |
— |
|
$ |
481 |
|
(1) Contracts include futures and fixed price swaps
(2) Contracts include basis swaps
The overall portfolio of the Company’s energy derivatives held for risk management purposes approximates the notional quantity of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk, and as applicable, anticipated transactions occur as expected.
In July of 2004, the Company entered into three 7.5 year secured variable share forward transactions. Each transaction has a different counterparty, covers 2.0 million shares of Kerr-McGee common stock, contains a collar and permits receipt of an amount up to the net present value of the floor price prior to maturity. The economic characteristics of any receipt would be considered that of a borrowing. Upon maturity of each transaction, the Company is obligated to deliver to the applicable counterparty, at the Company’s option, no more than 2.0 million Kerr-McGee shares or cash in an equivalent value. The transactions hedge the Company’s cash flow exposure of the forecasted disposal of the Kerr-McGee shares by effectively purchasing a put option from and selling a call option to the counterparty (collectively, the collar). The collars had no net cost for the Company. The collars effectively limit the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares between a blended average floor price per share of $53.06 and a blended average cap price per share of $100.79. Each transaction is secured by the underlying Kerr-McGee shares. A variable portion of the dividends received on the underlying Kerr-McGee shares must be paid to each counterparty depending upon the hedged position of such counterparty. Based on the current hedged position of the counterparties, the Company expects to pay to each counterparty approximately 67% of the next Kerr-McGee dividend. In the second half of 2004, the Company recorded pre-tax dividend income, net of payments to the counterparties, of $3.1 million, which is recorded in other income, net on the Statement of
73
Consolidated Income for the year ended December 31, 2004. At December 31, 2004, the Company owns approximately 7.0 million Kerr-McGee shares, of which approximately 1.0 million shares remain unhedged.
The variable share forward transactions meet the requirements of Statement No. 133 Implementation Issue G20, “Assessing and Measuring the Effectiveness of an Option Used in a Cash Flow Hedge” and have been designated as cash flow hedges. Under this guidance, complete hedging effectiveness is assumed and the entire change in fair value of the collars will be recorded in other comprehensive income. As of December 31, 2004, the projected price per share on the hedge expiration date of the Kerr-McGee shares was between the floor price and the cap price for each of these transactions. As such, no amounts have been recorded in the Consolidated Balance Sheet as of December 31, 2004 related to any change in the fair value of the collars.
4. Sale of Property
In February 2003, the Company sold approximately 500 of its low-producing natural gas wells, within two of its non-strategic districts, in two separate transactions. The sales resulted in a decrease of 13.0 Bcf of net reserves and generated proceeds of approximately $6.6 million. The wells produced an aggregate of approximately 1.0 Bcf in 2002. The Company did not recognize a gain or a loss as a result of this disposition.
5. Acquisitions
In February 2003, the Company purchased the remaining 31% limited partnership interest in Appalachian Basin Partners, LP (ABP) from the minority interest holders for $44.2 million. The 31% limited partnership interest represents approximately 60.2 Bcf of reserves. The ABP partnership was formed in November 1995 when the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit. The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target, which was met near the end of 2001. The Company consequently consolidated the partnership starting in 2002, and the partnership interest not owned by the Company was recorded as minority interest. As a result of the purchase of the 31% limited partner interest, effective February 1, 2003, the Company no longer recognized minority interest expense associated with ABP, which totaled $0.9 million and $7.1 million for the years ended December 31, 2003 and 2002, respectively.
74
6. Income Taxes
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
|
|
|
December 31, |
|
||||
|
|
|
2004 |
|
2003 |
|
||
|
|
|
(Thousands) |
|
||||
|
Deferred tax liabilities (assets): |
|
|
|
|
|
||
|
Drilling and development costs expensed for income tax reporting |
|
$ |
311,199 |
|
$ |
267,013 |
|
|
Other comprehensive (loss) income |
|
(113,558 |
) |
2,084 |
|
||
|
Tax depreciation in excess of book depreciation |
|
191,828 |
|
221,698 |
|
||
|
Regulatory temporary differences |
|
26,935 |
|
24,507 |
|
||
|
Deferred purchased gas cost |
|
5,760 |
|
(972 |
) |
||
|
Undistributed earnings of foreign subsidiaries |
|
— |
|
1,047 |
|
||
|
Deferred revenues/expenses |
|
(3,093 |
) |
(16,421 |
) |
||
|
Alternative minimum tax |
|
(3,900 |
) |
(28,060 |
) |
||
|
Investment tax credit |
|
(4,341 |
) |
(4,759 |
) |
||
|
Uncollectible accounts |
|
(13,241 |
) |
(6,495 |
) |
||
|
Postretirement benefits |
|
(7,972 |
) |
(5,820 |
) |
||
|
Kerr McGee book basis in excess of tax basis |
|
105,137 |
|
— |
|
||
|
Other |
|
(15,995 |
) |
(1,412 |
) |
||
|
Total (including amounts classified as current assets of $7,482 and $7,467 for 2004 and 2003, respectively) |
|
$ |
478,759 |
|
$ |
452,410 |
|
The net deferred tax asset relating to the Company’s other comprehensive income balance as of December 31, 2004 was comprised of a $121.2 million deferred tax asset relating to the Company’s net unrealized loss from hedging transactions, an $11.0 million deferred tax asset related to the minimum pension adjustment, and an $18.6 million deferred tax liability relating to the Company’s net unrealized gain on available-for-sale securities. The net deferred tax liability relating to the Company’s other comprehensive income balance as of December 31, 2003 was comprised of a $54.0 million deferred tax liability relating to the Company’s net unrealized gain on available-for-sale securities, a $38.7 million deferred tax asset relating to the Company’s net unrealized loss from hedging transactions, and a $13.2 million deferred tax asset related to the minimum pension adjustment.
Income tax expense is summarized as follows:
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
(Thousands) |
|
|||||||
|
Current: |
|
|
|
|
|
|
|
|||
|
Federal |
|
$ |
29,508 |
|
$ |
7,109 |
|
$ |
28,790 |
|
|
State |
|
329 |
|
5,599 |
|
5,647 |
|
|||
|
Foreign |
|
1,084 |
|
— |
|
286 |
|
|||
|
Subtotal |
|
30,921 |
|
12,708 |
|
34,723 |
|
|||
|
|
|
|
|
|
|
|
|
|||
|
Deferred: |
|
|
|
|
|
|
|
|||
|
Federal |
|
109,344 |
|
66,675 |
|
38,360 |
|
|||
|
State |
|
6,420 |
|
2,409 |
|
3,968 |
|
|||
|
Foreign |
|
(3,991 |
) |
— |
|
541 |
|
|||
|
Subtotal |
|
111,773 |
|
69,084 |
|
42,869 |
|
|||
|
Total |
|
$ |
142,694 |
|
$ |
81,792 |
|
$ |
77,592 |
|
75
Provisions for income taxes differ from amounts computed at the Federal statutory rate of 35% on pretax income from continuing operations. The reasons for the difference are summarized as follows:
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
(Thousands) |
|
|||||||
|
Tax at statutory rate |
|
$ |
147,891 |
|
$ |
89,371 |
|
$ |
79,876 |
|
|
State income taxes |
|
1,394 |
|
5,206 |
|
6,250 |
|
|||
|
Differences from foreign operations, including foreign taxes |
|
(1,140 |
) |
(5,140 |
) |
1,865 |
|
|||
|
Nonconventional fuels tax credit |
|
— |
|
(2,095 |
) |
(9,415 |
) |
|||
|
Percentage depletion basis differences |
|
(630 |
) |
(1,958 |
) |
— |
|
|||
|
Charitable contribution basis differences |
|
(489 |
) |
(3,162 |
) |
— |
|
|||
|
Subsidiary sale basis differences |
|
(2,096 |
) |
— |
|
— |
|
|||
|
Other |
|
(2,236 |
) |
(430 |
) |
(984 |
) |
|||
|
Income tax expense |
|
$ |
142,694 |
|
$ |
81,792 |
|
$ |
77,592 |
|
|
Effective tax rate |
|
33.8 |
% |
32.0 |
% |
34.0 |
% |
|||
Separate effective income tax rates are calculated for income from continuing operations, discontinued operations and cumulative effects of accounting changes. See Note 7 as to the tax impact of discontinued operations and Note 1 and Note 12 as to the tax impact of cumulative effects of accounting changes.
An income tax benefit of $7.8 million, $9.3 million, and $7.3 million for the years ended December 31, 2004, 2003 and 2002, respectively, triggered by the exercise of nonqualified employee stock options, is reflected as an addition to common stockholders’ equity.
As a result of the donation on June 30, 2004 of appreciated shares of Kerr-McGee to Equitable Resources Foundation, Inc. (see Note 10), the Company reported a tax benefit of approximately $6.8 million ($0.5 million permanent tax benefit). On March 31, 2003, the Company contributed appreciated shares of Westport Resources Corporation to this foundation resulting in a tax benefit of $7.1 million ($3.9 million permanent tax benefit). A gift of qualified appreciated stock allows for a tax deduction based on the fair market value of the gifted stock.
As a result of the Company’s increased partnership interest in ABP in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit attributable to ABP. This resulted in a reduction of the Company’s effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002 and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future. The Company’s effective tax rate was reduced in 2003 for nonconventional fuels tax credits not recorded in prior years.
In December 2004, the Company repatriated $3.9 million of off-shore earnings related to several international infrastructure projects in the NORESCO segment. Under the American Jobs Creation Act of 2004, this dividend will be taxed at an effective tax rate of approximately 6% instead of the statutory tax rate of 35%. Deferred taxes had previously been provided on these earnings at the higher tax rate.
The consolidated Federal income tax liability of the Company has been settled with the Internal Revenue Service (IRS) through 1997. The IRS is currently reviewing the Company’s Federal income tax filings for the 1998 through 2000 years. Upon completion of this examination, the Joint Committee of Taxation (a joint committee of Congress) should need to approve the findings due to a refund claim. The Company also is the subject of various routine state income tax examinations. The Company believes that it is appropriately reserved for any tax exposures.
The Company has estimated an AMT credit carryforward of $3.9 million at December 31, 2004 that it believes will be utilized against future Federal income tax liabilities. The Company has recorded a deferred tax
76
asset of $2.1 million, net of valuation allowances of $6.2 million, related to tax benefits from state net operating loss carryforwards with various expiration dates.
7. Discontinued Operations
In December 1998, the Company sold its natural gas midstream operations. A capital loss was treated as a nondeductible item for tax reporting purposes under the then current Treasury regulations embodying the “loss disallowance rule,” resulting in additional tax recorded on this sale as a reduction to income from discontinued operations. In May 2002, the IRS issued new Treasury regulations interpreting the “loss disallowance rule” that permitted this capital loss to be treated as deductible. During June 2002, the Company filed an amended tax return. Consequently, in the second quarter 2002, the Company recorded a $9.0 million increase in income from discontinued operations related to this unexpected tax benefit.
8. Restricted Cash
In 2001, the net proceeds from the sale of certain properties were placed in an escrow account pursuant to a deferred exchange agreement. This agreement allowed for the use of the funds in a potential like-kind exchange for certain identified assets. During 2002, the restrictions lapsed and the cash was made available for operations.
9. Equity in Nonconsolidated Investments
The Company has ownership interests in various nonconsolidated investments that are accounted for under the equity method of accounting. The following table summarizes the equity in nonconsolidated investments.
|
|
|
|
|
Interest |
|
Ownership |
|
December 31, |
|
||||
|
Investees |
|
Location |
|
Type |
|
2004 |
|
2004 |
|
2003 |
|
||
|
|
|
|
|
|
|
|
|
(Thousands) |
|
||||
|
Eastern Seven Partners, L.P. |
|
USA |
|
Limited |
|
1% |
|
$ |
26,009 |
|
$ |
26,055 |
|
|
Appalachian Natural Gas Trust |
|
USA |
|
Limited |
|
1% |
|
35,616 |
|
35,745 |
|
||
|
Total Equitable Supply |
|
|
|
|
|
|
|
61,625 |
|
61,800 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
IGC/ERI Pan-Am Thermal Generating Limited |
|
Panama |
|
Limited |
|
50% |
|
— |
|
21,693 |
|
||
|
Compania Hidroeletrico Dona Julia, S.D.R. Ltd. |
|
Costa Rica |
|
Limited |
|
24% |
|
2,828 |
|
5,639 |
|
||
|
Other |
|
USA |
|
Limited |
|
Various |
|
103 |
|
43 |
|
||
|
Total NORESCO |
|
|
|
|
|
|
|
2,931 |
|
27,375 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Total equity in nonconsolidated investments |
|
|
|
|
|
|
|
$ |
64,556 |
|
$ |
89,175 |
|
The Company did not make any additional equity investments in nonconsolidated investments during 2004 or 2003 and has a total cumulative investment in nonconsolidated entities of $64.6 million as of December 31, 2004. The Company’s ownership share of the earnings for 2004, 2003 and 2002 related to the total investments, excluding Westport was $2.0 million, $3.1 million and $5.0 million, respectively. All NORESCO segment projects have been completed using nonrecourse debt at the nonconsolidated entity level.
Certain NORESCO projects are conducted through nonconsolidated entities that consist of private power generation facilities located in select international locations. During the second quarter of 2004, several negative circumstances caused the Company to revisit its international investments for additional impairments and to accelerate its plans to exit the international generation business. Changes in pricing in the electricity power market
77
in Panama during the second quarter of 2004 negatively impacted the outlook for operations of IGC/ERI Pan Am Thermal Generating Limited (Pan Am), a Panamanian electric generation project. As a result, the Company performed an impairment analysis of its equity interest in this project. This involved preparing a probability-weighted cash flow analysis using the undiscounted future cash flows and comparing this amount to the book value of the equity investment. The probability-weighted cash flows resulted in a lower fair value than the carrying value, and an impairment was deemed necessary. An impairment of $22.1 million was recorded in the second quarter of 2004 and represents the full value of NORESCO’s equity investment in the project.
During the second quarter of 2004, the Company also reviewed its investment in Compania Hidroelectrica Dona Julia, S.D.R. Ltd. (Dona Julia), a Costa Rican electric generation project, as the investment was being actively marketed for sale. Based on the analysis performed on the sales value of the investment, the Company recorded an impairment charge of $2.8 million to write down the investment to its fair value less costs to sell. Following the impairment, the investment in Dona Julia was considered held for sale. The investment was included in equity in nonconsolidated investments on the Consolidated Balance Sheet at December 31, 2004.
Additional impairment charges of $15.3 million were also recorded in the second quarter of 2004 for total impairment charges of $40.2 million. The additional charges related to various costs and obligations related to exiting NORESCO’s investments in international power plant projects. Included in these charges was a liability for loan guarantees in the amount of $5.8 million in support of a 50% owned non-recourse financed energy project known as Pan Am. The impairment charges were reviewed during the fourth quarter of 2004 and reduced by $0.6 million. The entire impairment charge has been included in international investments, primarily impairment on the Statement of Consolidated Income for the year ended December 31, 2004.
During the fourth quarter of 2003, the Company reviewed its equity investment related to Petroelectrica de Panama LDC, an independent power plant in Panama. As a result of the analysis performed, an impairment of $11.1 million was recorded in the fourth quarter of 2003 which represented the full value of NORESCO’s equity investment in the project. The plant has been dismantled and final closure will take place in 2005.
In June 2003, the Company reevaluated its interest in Hunterdon Cogeneration LP (Hunterdon) and concluded that the Company effectively controlled Hunterdon for consolidation purposes. As a result, the Company began consolidating Hunterdon’s financial condition, results of operations and cash flows as of June 30, 2003 in the NORESCO segment.
The Company adopted FIN No. 46 for variable interest entities created or acquired prior to February 1, 2003 as of July 1, 2003. The adoption of FIN No. 46 required the consolidation of Plymouth Cogeneration LP’s (Plymouth) financial position, results of operations and cash flows as of July 1, 2003, as NORESCO is the primary beneficiary of Plymouth. In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R) that modified some of the provisions of FIN No. 46 and provided exemptions to certain entities from the original guidance. The Company adopted FIN No. 46R in the first quarter of 2004. The adoption of FIN No. 46R required the Company to deconsolidate Plymouth as of January 1, 2004, due to certain modifications of the original FIN No. 46 provisions. This deconsolidation returned Plymouth to the equity method of accounting for investments. The Company restored the equity investment in Plymouth of $0.1 million and decreased minority interest by $0.6 million in the Consolidated Balance Sheet. As of January 1, 2004, $4.9 million of assets and $4.9 million of liabilities, including nonrecourse debt of $4.0 million, were removed from the Consolidated Balance Sheet. The investment in Plymouth is included in “Other” in the table above.
Equitable Supply’s equity in nonconsolidated investments represents ownership interests in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. Both of these investments follow the equity method of accounting.
In 2002, Equitable Supply transferred one-third of its ownership in ANGT to an affiliated company. As of December 31, 2004 and 2003, Equitable Supply’s investment in ANGT totaled $23.7 million and $23.8 million, respectively, while the Company’s total investment was $35.6 million and $35.7 million, respectively.
78
The following tables summarize the financial information for nonconsolidated investments accounted for under the equity method of accounting:
Summarized Balance Sheets
|
|
|
December 31, 2004 |
|
||||
|
|
|
Supply |
|
NORESCO |
|
||
|
|
|
(Thousands) |
|
||||
|
Current assets |
|
$ |
26,615 |
|
$ |
10,540 |
|
|
Noncurrent assets |
|
287,784 |
|
14,899 |
|
||
|
Total assets |
|
$ |
314,399 |
|
$ |
25,439 |
|
|
|
|
|
|
|
|
||
|
Current liabilities |
|
$ |
17 |
|
$ |
4,071 |
|
|
Noncurrent liabilities |
|
— |
|
10,832 |
|
||
|
Stockholders equity |
|
314,382 |
|
10,536 |
|
||
|
Total liabilities and stockholders equity |
|
$ |
314,399 |
|
$ |
25,439 |
|
|
|
|
December 31, 2003 |
|
||||
|
|
|
Supply |
|
NORESCO |
|
||
|
|
|
(Thousands) |
|
||||
|
Current assets |
|
$ |
17,412 |
|
$ |
35,499 |
|
|
Noncurrent assets |
|
352,373 |
|
119,021 |
|
||
|
Total assets |
|
$ |
369,785 |
|
$ |
154,520 |
|
|
|
|
|
|
|
|
||
|
Current liabilities |
|
$ |
28 |
|
$ |
17,551 |
|
|
Noncurrent liabilities |
|
— |
|
60,375 |
|
||
|
Stockholders equity |
|
369,757 |
|
76,594 |
|
||
|
Total liabilities and stockholders equity |
|
$ |
369,785 |
|
$ |
154,520 |
|
79
Summarized Statements of Income
|
|
|
Year Ended December 31, 2004 |
|
||||
|
|
|
Supply |
|
NORESCO |
|
||
|
|
|
(Thousands) |
|
||||
|
Revenues |
|
$ |
125,323 |
|
$ |
9,265 |
|
|
Costs and expenses applicable to revenues |
|
— |
|
221 |
|
||
|
Net revenues |
|
125,323 |
|
9,044 |
|
||
|
Operating expenses |
|
67,825 |
|
5,607 |
|
||
|
Operating income |
|
57,498 |
|
3,437 |
|
||
|
Other expense |
|
— |
|
1,116 |
|
||
|
Income tax expense |
|
— |
|
5 |
|
||
|
Net income |
|
$ |
57,498 |
|
$ |
2,316 |
|
|
|
|
Year Ended December 31, 2003 |
|
||||
|
|
|
Supply |
|
NORESCO |
|
||
|
|
|
(Thousands) |
|
||||
|
Revenues |
|
$ |
117,174 |
|
$ |
84,557 |
|
|
Costs and expenses applicable to revenues |
|
— |
|
1,337 |
|
||
|
Net revenues |
|
117,174 |
|
83,220 |
|
||
|
Operating expenses |
|
60,298 |
|
67,207 |
|
||
|
Operating income |
|
56,876 |
|
16,013 |
|
||
|
Other expense |
|
— |
|
7,833 |
|
||
|
Income tax expense |
|
— |
|
767 |
|
||
|
Net income |
|
$ |
56,876 |
|
$ |
7,413 |
|
|
|
|
Year Ended December 31, 2002 |
|
|||||||
|
|
|
Supply |
|
NORESCO |
|
Westport |
|
|||
|
|
|
(Thousands) |
|
|||||||
|
Revenues |
|
$ |
86,934 |
|
$ |
79,728 |
|
$ |
428,430 |
|
|
Costs and expenses applicable to revenues |
|
— |
|
1,146 |
|
28,862 |
|
|||
|
Net revenues |
|
86,934 |
|
78,582 |
|
399,568 |
|
|||
|
Operating expenses |
|
61,722 |
|
64,031 |
|
414,624 |
|
|||
|
Operating income (loss) |
|
25,212 |
|
14,551 |
|
(15,056 |
) |
|||
|
Other expense |
|
— |
|
2,103 |
|
33,062 |
|
|||
|
Income tax expense (benefit) |
|
— |
|
1,830 |
|
(19,552 |
) |
|||
|
Net income |
|
$ |
25,212 |
|
$ |
10,618 |
|
$ |
(28,566 |
) |
10. Investments
As of December 31, 2004, the investments classified by the Company as available-for-sale include approximately $20.6 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures and a $406.1 million investment in Kerr-McGee.
On April 7, 2004, Westport announced a merger with Kerr-McGee. On June 25, 2004, Kerr-McGee and Westport completed the merger. Under the terms of the merger agreement, the Company received 0.71 shares of Kerr-McGee for each Westport share owned, or 8.2 million shares of Kerr-McGee. As a result of the merger, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for the Kerr-McGee shares.
80
The Company recorded its book basis in the Kerr-McGee shares at $49.82 per share, which included a discount to the market price for trading restrictions on the securities. The discount was recorded as a reduction to the increase in the book basis of the Kerr-McGee shares and was accreted into other comprehensive income during the third quarter of 2004.
Subsequent to the completion of the Kerr-McGee/Westport merger, the Company sold 800,000 Kerr-McGee shares for proceeds of $42.9 million. The sale resulted in the Company recognizing a gain of $3.0 million in the second quarter of 2004 which is included in gain on sale of available-for-sale securities on the Statement of Consolidated Income for the year ended December 31, 2004. The proceeds of $42.9 million on the sale of the shares were received in the third quarter of 2004. The Company utilizes the specific identification method to determine the cost of securities sold.
Following the Kerr-McGee/Westport merger, the Company entered into three variable share forward transactions in the third quarter 2004 related to an aggregate of 6.0 million Kerr-McGee shares. See Note 3 for discussion of these transactions.
On June 30, 2004, the Company irrevocably committed to contribute 357,000 Kerr-McGee shares to Equitable Resources Foundation, Inc. which was established by the Company in 2003 to support development programs in the communities were the Company conducts business. This resulted in the Company recording a charitable foundation contribution expense of $18.2 million during the second quarter 2004, with a corresponding one-time tax benefit of $6.8 million. The shares were transferred to this foundation under this commitment during the third quarter of 2004. Charitable contributions of significantly appreciated qualified shares of stock, such as the Kerr-McGee shares, constitute a tax efficient use of the shares.
On March 31, 2003, the Company donated 905,000 Westport shares to Equitable Resources Foundation, Inc. The contribution resulted in charitable contribution expense of $9.3 million with a corresponding one-time tax benefit of approximately $7.1 million.
In the second half of 2004, the Company recorded pre-tax dividend income of $3.1 million related to its holdings in the Kerr-McGee shares. The dividend income is included in other income, net on the Statement of Consolidated Income for the year ended December 31, 2004.
During 2003, the Company sold approximately 1.48 million shares of Westport stock, resulting in a gross realized gain of $14.0 million. There were no realized gains or losses associated with the investments for the year ended December 31, 2002. The Company utilized the specific identification method to determine the cost of the securities sold.
Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Consolidated Balance Sheets as a component of equity, accumulated other comprehensive income. Information regarding the cost and fair value of the Company’s available-for-sale investments at December 31, 2004 and December 31, 2003 is presented in the tables below. At December 31, 2004, the corporate notes and bonds have been in a cumulative unrealized loss position for a period greater than twelve months; however, these securities experienced an unrealized gain from December 31, 2003 to December 31, 2004. The cumulative unrealized loss through December 31, 2004 relates primarily to fluctuations in interest rates. The Company performed an impairment analysis in accordance with Statement No. 115 and concluded that the decline below cost is temporary.
81
|
|
|
December 31, 2004 |
|
||||||||||||
|
|
|
Cost |
|
Gross |
|
Gross |
|
Fair |
|
||||||
|
|
|
(Thousands) |
|
||||||||||||
|
Investment in Kerr-McGee |
|
$ |
350,128 |
|
$ |
56,012 |
|
$ |
— |
|
$ |
406,140 |
|
||
|
Other corporate equity securities |
|
11,054 |
|
1,954 |
|
— |
|
13,008 |
|
||||||
|
Corporate notes and bonds |
|
7,751 |
|
— |
|
(127 |
) |
7,624 |
|
||||||
|
Total investments |
|
$ |
368,933 |
|
$ |
57,966 |
|
$ |
(127 |
) |
$ |
426,772 |
|
||
|
|
|
December 31, 2003 |
|
||||||||||||
|
|
|
Cost |
|
Gross |
|
Gross |
|
Fair |
|
||||||
|
|
|
(Thousands) |
|
||||||||||||
|
Investment in Westport |
|
$ |
190,557 |
|
$ |
153,668 |
|
$ |
— |
|
$ |
344,225 |
|
||
|
Other corporate equity securities |
|
10,824 |
|
928 |
|
— |
|
11,752 |
|
||||||
|
Corporate notes and bonds |
|
7,479 |
|
— |
|
(176 |
) |
7,303 |
|
||||||
|
Total investments |
|
$ |
208,860 |
|
$ |
154,596 |
|
$ |
(176 |
) |
$ |
363,280 |
|
||
11. Regulatory Assets
The following table summarizes the Company’s regulatory assets, net of amortization, as of December 31, 2004 and 2003. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of these assets.
|
|
|
December 31, |
|
||||
|
Description |
|
2004 |
|
2003 |
|
||
|
|
|
(Thousands) |
|
||||
|
Deferred taxes |
|
$ |
62,117 |
|
$ |
54,500 |
|
|
Delinquency Reduction Opportunity Program |
|
10,404 |
|
12,478 |
|
||
|
Other postemployment benefits (Statement No. 106) |
|
7,530 |
|
6,305 |
|
||
|
Deferred purchase gas costs |
|
14,666 |
|
1,396 |
|
||
|
Other |
|
161 |
|
1,431 |
|
||
|
Valuation allowance |
|
(13,004 |
) |
(7,000 |
) |
||
|
Total regulatory assets |
|
81,874 |
|
69,110 |
|
||
|
Amounts classified as other current assets |
|
14,666 |
|
1,396 |
|
||
|
Total long-term regulatory assets |
|
$ |
67,208 |
|
$ |
67,714 |
|
The regulatory asset associated with deferred taxes primarily represents deferred income taxes recoverable through future rates once the taxes become current. The Company is recovering the amortization of this asset through rates. The Company has also established a valuation allowance of $10.4 million and $0 million as of December 31, 2004 and 2003, respectively against the deferred tax regulatory asset.
The following regulatory assets do not earn a return on investment: deferred taxes, Delinquency Reduction Opportunity Program and other postemployment benefits (SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”). The associated remaining recovery period for the regulatory assets associated with both Delinquency Reduction Opportunity Program and other postemployment benefits is 10 years. The associated remaining recovery period for the regulatory assets associated with deferred taxes is variable depending on the life of the book/tax difference generating the deferred item.
82
A regulatory asset was recognized as of December 31, 2001 at Equitable Gas Company (Equitable Gas) associated with uncollectible accounts receivable mainly due to unusually high natural gas prices and unseasonably cold weather experienced during the winter of 2000-2001. The regulatory asset was initially established based upon the Company’s ability to recover these costs through a surcharge in rates. In the third quarter 2002, the PA PUC issued an order approving a Delinquency Reduction Opportunity Program that gives incentives to low-income customers to make payments which exceed their current bill amount in order to receive additional credits from the Company intended to speed the reduction of the customer’s delinquent balance. This program is funded through customer contributions and through the existing surcharge in rates. The Company has established a valuation allowance of $2.6 million and $7.0 million as of December 31, 2004 and 2003, respectively, against the Delinquency Reduction Opportunity Program asset.
12. Intangible Assets
In accordance with the requirements of Statement No. 142, the Company tested its goodwill for impairment as of January 1, 2002. The Company’s goodwill balance as of January 1, 2002 totaled $57.2 million and was entirely related to the NORESCO segment. The fair value of the Company’s goodwill was estimated using discounted cash flow methodologies and market comparable information. As a result of the 2002 impairment test, the Company recognized an impairment of $5.5 million, net of tax, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment were expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment was reported as the cumulative effect of an accounting change in the Company’s Statements of Consolidated Income retroactive to the first quarter 2002. The tax impact of the impairment was zero since the Company’s goodwill had no tax basis. In the fourth quarter of 2004, 2003 and 2002, the Company performed the required annual impairment test of the carrying amount of goodwill and no further impairment was required.
13. Short-Term Loans
Maximum lines of credit of $500 million were available to the Company at December 31, 2004 and 2003, respectively. The Company is not required to maintain compensating bank balances. The Company’s credit ratings, as determined by either Standard & Poor’s or Moody’s on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s credit rating, the higher the level of fees and borrowing rate. As of December 31, 2004, the Company had not borrowed any amounts against these lines of credit. Commitment fees averaging one-eleventh of one percent in both 2004 and 2003 were paid to maintain credit availability.
Short-term loans were comprised of commercial paper balances of $295.5 million and $199.6 million with weighted average annual interest rates of 2.33% and 1.08% as of December 31, 2004 and 2003, respectively. The maximum amount of outstanding short-term loans at any certain time during the year was $397.5 million in 2004 and $229.6 million in 2003. The average daily balance of short-term loans outstanding over the course of the year was approximately $185.2 million and $106.1 million at weighted average annual interest rates of 1.65% and 1.19% during 2004 and 2003, both respectively.
In July of 2004, the Company entered into three 7.5 year secured variable share forward transactions to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares (See Note 3). Each transaction permits receipt of an amount up to the net present value of the floor price prior to maturity. The economic characteristics of any receipt would be considered that of a borrowing.
83
14. Long-Term Debt
|
|
|
December 31, |
|
||||||
|
|
|
2004 |
|
2003 |
|
||||
|
|
|
(Thousands) |
|
||||||
|
5.15% notes, due March 1, 2018 |
|
$ |
200,000 |
|
$ |
200,000 |
|
||
|
|
|
|
|
|
|
||||
|
5.15% notes, due November 15, 2012 |
|
200,000 |
|
200,000 |
|
||||
|
|
|
|
|
|
|
||||
|
7.75% debentures, due July 15, 2026 |
|
115,000 |
|
115,000 |
|
||||
|
|
|
|
|
|
|
||||
|
Medium-term notes: |
|
|
|
|
|
||||
|
8.0% to 9.0% Series A, due 2006 thru 2021 |
|
53,500 |
|
53,500 |
|
||||
|
6.5% to 7.6% Series B, due 2005 thru 2023 |
|
40,000 |
|
60,500 |
|
||||
|
6.8% to 7.6% Series C, due 2007 thru 2018 |
|
18,000 |
|
18,000 |
|
||||
|
Other |
|
1,851 |
|
6,414 |
|
||||
|
|
|
628,351 |
|
653,414 |
|
||||
|
Less debt payable within one year |
|
10,582 |
|
21,267 |
|
||||
|
Total long-term debt |
|
$ |
617,769 |
|
$ |
632,147 |
|
||
In February 2003, the Company issued $200 million of Notes with a stated interest rate of 5.15% and a maturity date of March 2018. A portion of the proceeds from the issuance was used to redeem the Company’s entire $125 million of 7.35% Trust Preferred Capital Securities on April 23, 2003. No gain or loss was incurred as a result of this redemption. The remainder of the proceeds from the February 2003 issuance was designated for general corporate purposes. The effective annual interest rate on the $200 million of notes is 5.22% after taking into consideration capitalized transaction costs and fees associated with the offering. Effective September 30, 2003, the Company offered all holders of its 5.15% Notes due 2018 the opportunity to exchange their Notes for a new issue of registered Notes pursuant to a Registratio n Statement on Form S-4. The exchange Notes were identical in all material respects to the Notes being exchanged, except that the exchange Notes did not have terms restricting their transfer or any terms related to registration rights. All original Notes were exchanged for the new issue of registered Notes as of December 31, 2003.
The Company issued $200 million of notes on November 15, 2002 with a stated interest rate of 5.15% and a maturity date of November 15, 2012 to pay down commercial paper. In September 2002, the Company entered into interest rate swap agreements with a notional amount of $150 million to hedge the risk of movement in interest rates from the date of the swap agreements to the date of issuance of the long-term debt. On November 15, 2002, shortly after the issuance of the long-term debt, the Company terminated the swap agreements by remitting approximately $1.2 million to the counterparties to the agreements. As these swap agreements were designated at inception as being cash flow hedges and were deemed to be effective, the $1.2 million was included in accumulated other comprehensive income on the Consolidated Balance Sheets and will be reclassified to interest expense in the periods in which the Company’s earnings are impacted by the hedged item. The Company estimates that approximately $0.1 million of the net unrealized losses related to the settlement of its interest rate swaps will be recognized in earnings during the next twelve months. The effective annual interest rate on the $200 million of notes is 5.30% after taking into consideration capitalized transaction costs and fees associated with the offering and the effect of the $150 million of interest rate swap agreements that were settled upon issuance of the long-term debt.
Other debt at December 31, 2004 primarily consists of long-term debt obligations of Hunterdon, which was consolidated during 2003. See Note 9 for further discussion on the consolidation of Hunterdon.
As of December 31, 2004, the Company has the ability to issue $100 million of additional long-term debt under the provisions of shelf registrations filed with the Securities and Exchange Commission.
The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets, and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, in the event that the Company’s
84
debt rating changes, this event would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.
Interest expense on long-term debt amounted to $39.1 million in 2004, $39.3 million in 2003, and $23.8 million in 2002. Aggregate maturities of long-term debt are $10.6 million in 2005, $3.6 million in 2006, $10.7 million in 2007, $0 in 2008, and $4.3 million in 2009.
15. Prepaid Forward Contract
In 2000, the Company entered into two prepaid natural gas sales contracts pursuant to which the Company was required to sell and deliver 52.7 Bcf of natural gas during the term of the contracts. The first contract was for five years with net proceeds of $104.0 million. The second contract was for three years with net proceeds of $104.8 million and was completed at the end of 2003. These contracts were recorded as prepaid forward sales, and the related income was recognized as deliveries occurred.
In June 2004, the Company continued to evaluate its capital structure as a result of the anticipated increase in liquidity expected as a result of the Westport/Kerr-McGee merger. Based on this evaluation, the Company amended the remaining prepaid natural gas contract. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company’s obligation to deliver a fixed quantity of gas at a fixed price has not changed but the amendment has the effect of increasing the realized sales price for the delivery of gas for the remaining term of the contract. As such, the Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the balance sheet and recorded a loss in the second quarter of $5.5 million in other income, net in the Statement of Consolidated Income reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue. Prospectively, through the term of the remaining contract (December 2005), the Company will deliver the required quantity of gas at an effective price of $4.79 per Mcf rather than $3.99 per Mcf as originally stated in the contract. Income will continue to be recognized upon delivery of the gas.
16. Pension and Other Postretirement Benefit Plans
The Company has defined benefit pension and other postretirement benefit plans covering represented members that generally provide benefits of stated amounts for each year of service. Prior to 2003, the Company provided benefits to certain non-represented employees through defined benefit plans that used a benefit formula based upon employee compensation. Effective December 31, 2003, the pension benefits provided to the non-represented employees through this plan were frozen and the covered non-represented employees were converted to a defined contribution plan. Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees whose benefits were frozen as of December 31, 2003. As a result of this settlement, which was accounted for under SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement expense of $13.4 million as of December 31, 2004. The settlement expense that was recognized for these non-represented employees was primarily the result of accelerated recognition of approximately $11.0 million in previously deferred unrecognized losses. Additionally, the pension settlement expense is an unallocated expense in deriving total operating income for segment reporting purposes (see Note 2). As part of this settlement, the affected employees were provided the option to either roll over the lump-sum value of their cash balance account to the Company’s defined contribution plan, or to receive an insured monthly annuity benefit at the time they retire. All other non-represented employees are participants in a defined contribution plan. The Company uses a December 31 measurement date for its defined benefit pension and other postretirement plans.
85
The following table sets forth the defined benefit pension and other postretirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets:
|
|
|
Pension Benefits |
|
Other Benefits |
|
||||||||
|
|
|
2004 |
|
2003 |
|
2004 |
|
2003 |
|
||||
|
|
|
(Thousands) |
|
||||||||||
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
||||
|
Benefit obligation at beginning of year |
|
$ |
116,947 |
|
$ |
112,748 |
|
$ |
52,769 |
|
$ |
47,929 |
|
|
Service cost |
|
1,590 |
|
2,684 |
|
483 |
|
313 |
|
||||
|
Interest cost |
|
6,970 |
|
7,553 |
|
3,273 |
|
3,467 |
|
||||
|
Amendments |
|
— |
|
144 |
|
— |
|
— |
|
||||
|
Actuarial loss |
|
5,038 |
|
9,363 |
|
6,445 |
|
7,024 |
|
||||
|
Benefits paid |
|
(7,821 |
) |
(7,875 |
) |
(7,297 |
) |
(5,964 |
) |
||||
|
Expenses paid |
|
(352 |
) |
(732 |
) |
— |
|
— |
|
||||
|
Curtailments |
|
2,434 |
|
(1,007 |
) |
— |
|
— |
|
||||
|
Settlements |
|
(8,551 |
) |
(5,931 |
) |
— |
|
— |
|
||||
|
Benefit obligation at end of year |
|
$ |
116,255 |
|
$ |
116,947 |
|
$ |
55,673 |
|
$ |
52,769 |
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
||||
|
Fair value of plan assets at beginning of year |
|
$ |
108,311 |
|
$ |
57,116 |
|
$ |
— |
|
$ |
— |
|
|
Gain recognized at beginning of year |
|
3 |
|
270 |
|
— |
|
— |
|
||||
|
Actual gain (loss) on plan assets |
|
8,917 |
|
13,623 |
|
— |
|
— |
|
||||
|
Employer contribution |
|
— |
|
51,840 |
|
— |
|
— |
|
||||
|
Benefits paid |
|
(7,821 |
) |
(7,875 |
) |
— |
|
— |
|
||||
|
Expenses paid |
|
(352 |
) |
(732 |
) |
— |
|
— |
|
||||
|
Settlements |
|
(8,141 |
) |
(5,931 |
) |
— |
|
— |
|
||||
|
Fair value of plan assets at end of year |
|
$ |
100,917 |
|
$ |
108,311 |
|
$ |
— |
|
$ |
— |
|
|
Funded status |
|
$ |
(15,338 |
) |
$ |
(8,636 |
) |
$ |
(55,673 |
) |
$ |
(52,769 |
) |
|
Unrecognized net actuarial loss |
|
29,835 |
|
38,686 |
|
41,242 |
|
36,797 |
|
||||
|
Unrecognized prior service cost (credit) |
|
4,316 |
|
5,256 |
|
(448 |
) |
(490 |
) |
||||
|
Net amount recognized |
|
$ |
18,813 |
|
$ |
35,306 |
|
$ |
(14,879 |
) |
$ |
(16,462 |
) |
|
Amounts recognized in the statement of financial position consist of: |
|
|
|
|
|
|
|
|
|
||||
|
Accrued benefit liability |
|
$ |
(15,338 |
) |
$ |
(8,636 |
) |
$ |
(14,879 |
) |
$ |
(16,462 |
) |
|
Intangible asset |
|
4,316 |
|
5,256 |
|
— |
|
— |
|
||||
|
Accumulated other comprehensive loss |
|
19,691 |
|
25,532 |
|
— |
|
— |
|
||||
|
Deferred tax asset |
|
10,144 |
|
13,154 |
|
— |
|
— |
|
||||
|
Net amount recognized |
|
$ |
18,813 |
|
$ |
35,306 |
|
$ |
(14,879 |
) |
$ |
(16,462 |
) |
The pension liability of $15.3 million and $8.6 million as of December 31, 2004 and 2003, respectively, is included in other long-term liabilities. The accrued liability for other postretirement benefits of $14.9 million and $16.5 million as of December 31, 2004 and 2003, respectively, is also included in other long-term liabilities.
The accumulated benefit obligation for all defined benefit pension plans was $116.3 million and $116.9 million at December 31, 2004 and 2003, respectively.
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $116.3 million, $116.3 million, and $100.9 million, respectively, as of December 31, 2004, and were $116.9 million, $116.9 million, and $108.3 million, respectively, as of December 31, 2003.
86
The Company’s costs related to its defined benefit pension and other postretirement benefit plans were as follows:
|
|
|
Pension Benefits |
|
Other Benefits |
|
||||||||||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
2004 |
|
2003 |
|
2002 |
|
||||||
|
|
|
(Thousands) |
|
||||||||||||||||
|
Components of net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Service cost |
|
$ |
1,590 |
|
$ |
2,684 |
|
$ |
2,557 |
|
$ |
483 |
|
$ |
313 |
|
$ |
380 |
|
|
Interest cost |
|
6,970 |
|
7,553 |
|
8,102 |
|
3,273 |
|
3,467 |
|
3,465 |
|
||||||
|
Expected return on plan assets |
|
(9,828 |
) |
(8,660 |
) |
(9,711 |
) |
— |
|
— |
|
— |
|
||||||
|
Amortization of prior service cost |
|
940 |
|
1,286 |
|
1,281 |
|
(42 |
) |
(42 |
) |
(3 |
) |
||||||
|
Amortization of initial net (asset) obligation |
|
— |
|
— |
|
— |
|
— |
|
— |
|
674 |
|
||||||
|
Recognized net actuarial loss |
|
745 |
|
21 |
|
21 |
|
2,000 |
|
1,828 |
|
1,239 |
|
||||||
|
Special termination benefits |
|
— |
|
— |
|
81 |
|
— |
|
— |
|
— |
|
||||||
|
Settlement expense (a) |
|
13,394 |
|
— |
|
— |
|
— |
|
— |
|
— |
|
||||||
|
Settlement loss |
|
339 |
|
2,206 |
|
3,036 |
|
— |
|
— |
|
— |
|
||||||
|
Curtailment loss (b) |
|
2,434 |
|
2,181 |
|
— |
|
— |
|
— |
|
— |
|
||||||
|
Net periodic benefit cost |
|
$ |
16,584 |
|
$ |
7,271 |
|
$ |
5,367 |
|
$ |
5,714 |
|
$ |
5,566 |
|
$ |
5,755 |
|
(a) The 2004 settlement expense represents the settlement of the cash balance participants pension benefit obligation at December 31, 2004 for those non-represented employees whose benefits under the pension plan were frozen in 2003.
(b) The 2003 curtailment loss represents the conversion of approximately 340 non-represented employees from the Company’s defined benefit plan to a defined contribution plan.
The following weighted average assumptions were used to determine the benefit obligations and net periodic benefit cost for the Company’s defined benefit pension and other postretirement benefit plans.
|
|
|
Pension Benefits |
|
Other Benefits |
|
|||||||||
|
|
|
2004 |
|
2003 |
|
2004 |
|
2003 |
|
|||||
|
Discount rate |
|
6.00 |
% |
6.25 |
% |
6.00 |
% |
6.25 |
% |
|||||
|
Expected return on plan assets |
|
8.25 |
% |
8.75 |
% |
N/A |
|
N/A |
|
|||||
|
Rate of compensation increase |
|
N/A |
|
4.50 |
% |
N/A |
|
N/A |
|
|||||
The expected rate of return and the rate of compensation increase are established at the beginning of the fiscal year that they relate to based upon information available to the Company at that time, including the plans’ investment mix, the forecasted rates of return on these types of securities, and expected compensation charges. In determining the expected return on plan assets, the Company considered the historical rates of return earned on plan assets, an expected return percentage by asset class based upon a survey of investment managers and the Company’s actual and targeted investment mix. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company’s net periodic benefit cost in accordance with SFAS No. 87, “Employers’ Accounting for Pensions.” Effective December 31, 2003, the pension benefits provided through this plan for certain non-represented employees were frozen and the covered employees were converted to a defined contribution plan. Accordingly, the rate of compensation increase for 2004 and subsequent years is no longer applicable in determining future benefit obligations. The expected rate of return determined as of January 1, 2005 totaled 8.25%. This assumption will be used to derive the Company’s 2005 net periodic benefit cost.
87
For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2005 is 9.25% for both the Pre-65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 4.50% in 2009.
Assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
|
|
One-Percentage-Point |
|
One-Percentage-Point |
|
||||||||||||||||
|
|
|
(Thousands) |
|
(Thousands) |
|
||||||||||||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
2004 |
|
2003 |
|
2002 |
|
||||||||
|
Effect on total of service and interest cost components |
|
$ |
108 |
|
$ |
87 |
|
$ |
233 |
|
$ |
(104 |
) |
$ |
(81 |
) |
$ |
(208 |
) |
||
|
Effect on postretirement benefit obligation |
|
$ |
1,751 |
|
$ |
1,407 |
|
$ |
1,191 |
|
$ |
(1,659 |
) |
$ |
(1,316 |
) |
$ |
(1,114 |
) |
||
The Company’s pension asset allocation at December 31, 2004 and 2003 and target allocation for 2005 by asset category are as follows:
|
Asset Category |
|
Target |
|
Percentage of Plan Assets |
|
||
|
|
|
|
|
2004 |
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
Domestic broadly diversified equity securities |
|
50% - 70% |
|
56 |
% |
62 |
% |
|
Fixed income securities |
|
30% - 45% |
|
37 |
% |
36 |
% |
|
International broadly diversified equity securities |
|
0% - 15% |
|
6 |
% |
— |
|
|
Other |
|
0% - 10% |
|
1 |
% |
2 |
% |
|
|
|
|
|
100 |
% |
100 |
% |
The investment activities of the Company’s pension plan are supervised and monitored by the Benefits Investment Committee. The Benefits Investment Committee has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Benefits Investment Committee are to minimize high levels of risk at the total pension investment fund level. The Benefits Investment Committee monitors the actual asset allocation on a quarterly basis and adjustments are made, as needed, to rebalance the assets within the prescribed target ranges. Investment managers are retained by the Company to manage separate pools of assets, and funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that each of the firm’s investment managers is performing satisfactorily.
The Company made cash contributions totaling $51.8 million to its pension plan during the year ended December 31, 2003. The Company did not make a contribution to its defined benefit plan in 2004. The Company expects to make a cash contribution of $10.3 million to its pension plan during 2005 to fully fund the cash balance participants portion of the pension plan which was settled effective December 31, 2004. The following benefit payments, which reflect expected future service and the final settlement of the cash balance portion of the pension plan in 2005, are expected to be paid during each of the next five years and the five years thereafter: $28.2 million in 2005; $8.2 million in 2006; $8.1 million in 2007; $7.7 million in 2008; $8.3 million in 2009; and $37.5 million in the five years thereafter.
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. Additionally, the Act introduced a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company sponsors retiree medical programs for certain of its locations and expects that this legislation will reduce the Company’s costs for some of these programs in the future.
88
In May 2004, the FASB issued Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) which permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act. FSP FAS 106-2 superceded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” which was issued in January 2004. The specific regulations to specify how actuarial equivalency is to be determined under the Act were issued in February 2005. Based on the Company’s preliminary analysis, it appears that some of the Company’s retiree medical plans may need to be revised in order to qualify for beneficial treatment under the Act, while other plans may continue unchanged.
The Company has elected to defer financial recognition with respect to the effects of the Act pending completion of the review of the recently released regulations and their impact on the Company’s retiree medical plans. In accordance with FSP FAS 106-2, measures of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost in the consolidated financial statements or accompanying notes do not reflect any amounts associated with the subsidy as the Company was unable to conclude whether the benefits provided by its medical plans were actuarially equivalent to Medicare Part D under the Act, as the guidance pertaining to determining actuarial equivalency was just recently issued in February 2005.
Expense recognized by the Company related to its 401(k) employee savings plans totaled $4.5 million in 2004, $3.1 million in 2003 and $3.2 million in 2002.
17. Common Stock and Earnings Per Share
At December 31, 2004, shares of Equitable’s authorized and unissued common stock were reserved as follows:
|
|
|
(Thousands) |
|
|
|
|
|
|
|
Possible future acquisitions |
|
6,597 |
|
|
Stock compensation plans |
|
9,058 |
|
|
Total |
|
15,655 |
|
89
Earnings Per Share
The computation of basic and diluted earnings per common share is shown in the table below:
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
(Thousands, except per share amounts) |
|
|||||||
|
Basic earnings per common share: |
|
|
|
|
|
|
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
$ |
279,854 |
|
$ |
173,557 |
|
$ |
150,626 |
|
|
Income from discontinued operations |
|
— |
|
— |
|
9,000 |
|
|||
|
Cumulative effect of accounting change, net of tax |
|
— |
|
(3,556 |
) |
(5,519 |
) |
|||
|
Net income applicable to common stock |
|
$ |
279,854 |
|
$ |
170,001 |
|
$ |
154,107 |
|
|
Average common shares outstanding |
|
61,682 |
|
62,050 |
|
62,895 |
|
|||
|
Basic earnings per common share |
|
$ |
4.54 |
|
$ |
2.74 |
|
$ |
2.45 |
|
|
|
|
|
|
|
|
|
|
|||
|
Diluted earnings per common share: |
|
|
|
|
|
|
|
|||
|
Income from continuing operations before cumulative effect of accounting change |
|
$ |
279,854 |
|
$ |
173,557 |
|
$ |
150,626 |
|
|
Income from discontinued operations |
|
— |
|
— |
|
9,000 |
|
|||
|
Cumulative effect of accounting change, net of tax |
|
— |
|
(3,556 |
) |
(5,519 |
) |
|||
|
Net income applicable to common stock |
|
$ |
279,854 |
|
$ |
170,001 |
|
$ |
154,107 |
|
|
Average common shares outstanding |
|
61,682 |
|
62,050 |
|
62,895 |
|
|||
|
Potentially dilutive securities: |
|
|
|
|
|
|
|
|||
|
Stock options and awards (a) |
|
1,419 |
|
1,308 |
|
1,121 |
|
|||
|
Total |
|
63,101 |
|
63,358 |
|
64,016 |
|
|||
|
Diluted earnings per common share |
|
$ |
4.44 |
|
$ |
2.68 |
|
$ |
2.41 |
|
(a) Options to purchase 0 shares, 11,337 shares, and 1,217,660 shares of common stock were not included in the computation of diluted earnings per common share because the options’ exercise prices were greater than the average market prices of the common shares for 2004, 2003 and 2002, respectively.
18. Accumulated Other Comprehensive (Loss) Income
The components of accumulated other comprehensive (loss) income are as follows net of tax:
|
|
|
2004 |
|
2003 |
|
||
|
|
|
(Thousands) |
|
||||
|
|
|
|
|
|
|
||
|
Net unrealized loss from hedging transactions |
|
$ |
(198,185 |
) |
$ |
(59,656 |
) |
|
Unrealized gain on available-for-sale securities |
|
37,529 |
|
100,453 |
|
||
|
Minimum pension liability adjustment |
|
(19,691 |
) |
(25,532 |
) |
||
|
Accumulated other comprehensive (loss) income |
|
$ |
(180,347 |
) |
$ |
15,265 |
|
90
19. Stock-Based Compensation Plans
Long-Term Incentive Plans
The Company’s 1994 and 1999 Long-Term Incentive Plans (the Plans) provide for the granting of shares of common stock to officers and key employees of the Company. These grants may be made in the form of stock options, restricted stock, stock appreciation rights and other types of stock-based or performance-based awards as determined by the Compensation Committee of the Board of Directors at the time of each grant. Stock awarded under the Plans, or purchased through the exercise of options, and the value of stock appreciation units are restricted and subject to forfeiture should an optionee terminate employment prior to specified vesting dates. In no case may the number of shares granted under the Plans exceed 3,451,000 and 11,000,000 shares, respectively. Options granted under the Plans expire 6 to 10 years from the date of grant and some contain vesting provisions which are based upon the Company’s performance. During 2004, no new stock options were awarded. Grants reflected below for 2004 comprise options granted for reload rights associated with previously-awarded options.
Pro forma information regarding net income and earnings per share for options granted is required by Statement No. 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of Statement No. 123. The fair value for these option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the following assumptions for 2004, 2003, and 2002, respectively.
|
|
|
Years Ended December 31, |
|
|||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
Risk-free interest rate (range) |
|
1.95% to 4.34% |
|
2.35% to 3.72% |
|
3.25% to 5.26% |
|
|||
|
Dividend yield |
|
2.88% |
|
2.47% |
|
1.96% |
|
|||
|
Volatility factor |
|
.263 |
|
.251 |
|
.275 |
|
|||
|
Weighted average expected life of options |
|
7 years |
|
7 years |
|
7 years |
|
|||
|
Options granted |
|
63,429 |
|
540,915 |
|
1,547,146 |
|
|||
|
Weighted average fair market value of options granted during the year |
|
$ |
9.88 |
|
$ |
9.68 |
|
$ |
9.62 |
|
|
|
|
Years Ended December 31, |
|
|||||||||||||
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||||||||
|
|
|
Shares |
|
Weighted |
|
Shares |
|
Weighted |
|
Shares |
|
Weighted |
|
|||
|
Options outstanding January 1 |
|
4,888,008 |
|
$ |
28.45 |
|
6,166,004 |
|
$ |
26.55 |
|
6,068,464 |
|
$ |
22.94 |
|
|
Granted |
|
63,429 |
|
$ |
46.72 |
|
540,915 |
|
$ |
36.13 |
|
1,547,146 |
|
$ |
34.57 |
|
|
Forfeited |
|
(82,234 |
) |
$ |
34.65 |
|
(226,573 |
) |
$ |
34.12 |
|
(205,047 |
) |
$ |
29.56 |
|
|
Exercised |
|
(1,064,154 |
) |
$ |
26.70 |
|
(1,592,338 |
) |
$ |
22.90 |
|
(1,244,559 |
) |
$ |
18.42 |
|
|
Options outstanding December 31 |
|
3,805,049 |
|
$ |
29.11 |
|
4,888,008 |
|
$ |
28.45 |
|
6,166,004 |
|
$ |
26.55 |
|
|
Options exercisable December 31 |
|
3,109,037 |
|
$ |
27.77 |
|
3,125,647 |
|
$ |
25.21 |
|
2,851,920 |
|
$ |
21.55 |
|
91
Options outstanding at December 31, 2004 include 3,109,037 exercisable at that date and are summarized in the following table.
|
Options Outstanding |
|
Options Exercisable |
|
||||||||||||
|
Range of Exercise Prices |
|
Number |
|
Weighted |
|
Weighted |
|
Exercisable |
|
Weighted |
|
||||
|
$11.83 |
to |
$17.76 |
|
491,533 |
|
3.1 |
|
$ |
14.90 |
|
491,533 |
|
$ |
14.90 |
|
|
$17.77 |
to |
$23.68 |
|
592,317 |
|
5.2 |
|
$ |
19.85 |
|
592,317 |
|
$ |
19.85 |
|
|
$23.69 |
to |
$29.60 |
|
150,407 |
|
5.8 |
|
$ |
28.59 |
|
150,407 |
|
$ |
28.59 |
|
|
$29.61 |
to |
$35.52 |
|
1,999,202 |
|
6.7 |
|
$ |
33.06 |
|
1,601,143 |
|
$ |
32.71 |
|
|
$35.53 |
to |
$41.44 |
|
519,016 |
|
7.7 |
|
$ |
36.30 |
|
221,063 |
|
$ |
36.90 |
|
|
$41.45 |
to |
$47.36 |
|
42,884 |
|
6.3 |
|
$ |
44.54 |
|
42,884 |
|
$ |
44.54 |
|
|
$47.37 |
to |
$53.28 |
|
4,574 |
|
4.5 |
|
$ |
52.03 |
|
4,574 |
|
$ |
52.03 |
|
|
$53.29 |
to |
$59.20 |
|
5,116 |
|
4.9 |
|
$ |
56.68 |
|
5,116 |
|
$ |
56.68 |
|
The Company granted 143,000 stock units from the 1999 Long-Term Incentive Plan for the 2002 Executive Performance Incentive Program (2002 Plan). The 2002 Plan was established to provide additional incentive benefits to retain senior executive employees of the Company and to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. The vesting of these awards occurred on December 31, 2004 and resulted in approximately 276,000 units (191.7% of the award) being distributed. The 2002 Plan expense for the period ended December 31, 2004 was $7.0 million and is classified as selling, general and administrative expense. The stock units are not dilutive to the Company’s share count as the value of the stock units will be paid in cash or stock, at an employee’s election, during the first quarter 2005.
The Company granted 439,400 stock units for the 2003 Executive Performance Incentive Program (2003 Plan). As of December 31, 2004, 385,900 stock units remained outstanding under the 2003 plan. The 2003 Plan was established to provide additional incentive benefits to retain senior executive employees of the Company and to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. The vesting of these units will occur on December 31, 2005, contingent upon the level of total shareholder return relative to the 30 peer companies identified below and will result in the distribution of zero to 771,800 units (200% of the units). The Company anticipates, based on current estimates, that a certain level of performance will be met and has expensed a ratable estimate of the units accordingly. The 2003 Plan expense for the year ended December 31, 2004 was $19.2 million and is classified as selling, general and administrative expense. The stock units are not currently dilutive to the Company’s share count as the value of the stock units will be paid in cash or stock during the first quarter of 2006.
Under the 2003 Plan, the 30 peer companies may be adjusted by the Compensation Committee of the Company’s Board of Directors based on significant or unusual transactions or events that substantially affect the total shareholder return calculation of any company or that, for operational or non-operational reasons, do not reflect or otherwise skew the relevant performance metric intended to be measured. The Company uses different peer groups for other purposes. The current peer companies for the 2003 Plan are as follows:
92
|
AGL Resources Inc. |
|
|
ATMOS Energy Corp. |
|
|
Cascade Natural Gas Corp. |
|
|
CMS Energy Corp. |
|
|
Dynegy Inc. |
|
|
El Paso Corp. |
|
|
Energen Corp. |
|
|
Keyspan Corp. |
|
|
Kinder Morgan Inc. |
|
|
Laclede Group, Inc. |
|
|
MDU Resources Group Inc. |
|
|
National Fuel Gas Co. |
|
|
New Jersey Resources Corp. |
|
|
NICOR, Inc. |
|
|
NISOURCE Inc. |
|
|
Northwest Natural Gas Co. |
|
|
NUI Corp. |
|
|
OGE Energy Corp. |
|
|
ONEOK Inc. |
|
|
Peoples Energy Corp. |
|
|
Piedmont Natural Gas Co., Inc. |
|
|
Questar Corp. |
|
|
Sempra Energy |
|
|
Southern Union Co. |
|
|
Southwest Gas Corp. |
|
|
Southwestern Energy Co. |
|
|
UGI Corp. |
|
|
Westar Energy Inc. |
|
|
WGL Holdings, Inc. |
|
|
The Williams Companies, Inc. |
|
In 2004, 2003, and 2002, the Company granted 145,550, 70,510, and 116,300 additional stock awards, respectively, to key executives from the 1999 Long-Term Incentive Plan. The weighted average fair value per share of these restricted stock grants is $43.75, $35.59, and $32.92, respectively, for 2004, 2003, and 2002. The shares granted under these plans will be fully vested at the end of the three-year period commencing the date of grant. Compensation expense recorded by the Company related to stock awards was $3.8 million in 2004, $2.6 million in 2003, and $3.2 million in 2002.
Nonemployee Directors’ Stock Incentive Plans
The Company’s 1994 and 1999 Nonemployee Directors’ Stock Incentive Plans provide for the granting of up to 160,000 and 600,000 shares, respectively, of common stock in the form of stock option grants and restricted stock awards to nonemployee directors of the Company. The exercise price for each share is equal to market price of the common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant. At December 31, 2004, 102,252 options were outstanding under the 1999 Nonemployee Directors’ Stock Incentive Plan at prices ranging from $11.84 to $59.20 per share, and 246,800 options had been exercised under this plan since the plan inception. During 2004 and 2003, no options were outstanding or exercisable under the 1994 Nonemployee Directors’ Stock Incentive Plan.
20. Fair Value of Financial Instruments
The carrying value of cash and cash equivalents, as well as short-term loans, approximates fair value due to the short maturity of the instruments. The fair value of the available-for-sale securities is estimated based on quoted market prices for those investments.
The estimated fair value of long-term debt described in Note 14 at December 31, 2004 and 2003 was $689.1 million and $696.9 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity.
The estimated fair value of liabilities for derivative commodity instruments described in Note 3, excluding trading activities which are marked-to-market, was a $26.8 million asset and a $350.4 million liability at December 31, 2004 and a $34.5 million asset and a $137.6 million liability at December 31, 2003.
21. Concentrations of Credit Risk
Revenues and related accounts receivable from the Equitable Supply segment’s operations are generated primarily from the sale of produced natural gas to certain marketers, Equitable Energy, LLC (an affiliate), other Appalachian Basin purchasers, and utility and industrial customers located mainly in the Appalachian area; the sale of produced natural gas liquids to a gas processor in Kentucky; and gathering of natural gas in Kentucky, Virginia, Ohio, Pennsylvania and West Virginia.
93
The Equitable Utilities Distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 276,300 residential, commercial and industrial customers located in southwestern Pennsylvania, northern West Virginia and eastern Kentucky. The Pipeline operations include FERC-regulated interstate pipeline transportation and storage service for the affiliated utility, Equitable Gas, as well as other utility and end-user customers located in the northeastern United States. The unregulated Marketing operation provides commodity procurement and delivery, physical natural gas management operations and control, and customer support services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions.
Under previous state regulations, Equitable Gas was required to provide continuous natural gas service to residential customers during the winter heating season. However, on November 30, 2004, Pennsylvania Governor Edward G. Rendell signed into law the Responsible Utility Customer Protection Act (Act 201). Act 201, which became effective on December 14, 2004, established new procedures for utilities regarding collection activities with respect to deposits, payment plans and terminations for residential customers and is intended to help utility companies collect amounts due from customers. As a result of Act 201, the Company is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and complete customer terminations without approval from the PA PUC.
Approximately 66% and 52% of the Company’s accounts receivable balance as of December 31, 2004 and 2003, respectively, represents amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Company’s criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2004 and 2003.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. NYMEX traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength.
The NORESCO segment’s operating revenues and related accounts receivable are generated from performance contracts with federal, state, and local government, institutional customers throughout the United States and cogeneration and power plant facilities in several U.S. markets.
The Company is not aware of any significant credit risks that have not been recognized in provisions for doubtful accounts.
22. Commitments and Contingencies
The Company has annual commitments of approximately $29.7 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to eleven years as of December 31, 2004, which relate to natural gas distribution and production operations. However, approximately $20.3 million of these costs are recoverable in customer rates.
In the third quarter of 2003, the Company entered into a long-term lease with Continental Real Estate Companies (Continental) to occupy office space in a building at the North Shore in Pittsburgh. This action will help consolidate the Company’s administrative operations. Continental is constructing and will own the office building, which is expected to be completed in 2005. The term of the lease is 20 years and nine months and the base rent is approximately $2 million per year. Relocation of operations from locations that utilize space under long-term leases will likely cause additional expense in 2005.
In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the
94
ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company. It is the Company’s policy to recognize any legal costs associated with any claims and legal proceedings against the Company as they are incurred.
After an extended period of troubled operations, ERI JAM, LLC, a subsidiary that holds the Company’s interest in EAL/ERI Cogeneration Partners LP, an international infrastructure project located in Jamaica, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. In the third quarter 2003, ERI JAM, LLC transferred control of the international infrastructure project under the partnership agreement to the other non-affiliate general partner. The international infrastructure project was deconsolidated in accordance with FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.” In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM LLC as Debtor-in-Possession in the Chapter 11 case. EAL, an affiliate of JBG, is a limited partner in EAL/ERI Cogeneration Partners LP. In October 2003, JBG and EAL also filed a multi-count complaint seeking damages against Equitable and certain of its affiliates in U.S. District Court (Western District of Pennsylvania) alleging breach of contract, tortious interference with contractual relations, negligence and a variety of related claims with respect to the operation and management of EAL/ERI Cogeneration Partners LP. Equitable filed a Motion to Dismiss in September 2004, and subsequently agreed in principle with JBG and EAL to settle the litigation. The parties are currently negotiating the terms of a settlement agreement.
The various regulatory authorities that oversee Equitable’s operations will, from time to time, make inquiries or investigations into the activities of the Company. It is the Company’s policy to cooperate when regulatory bodies make requests.
The Company is subject to various federal, state and local environmental and environmentally related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations. The Company has identified situations that require remedial action for which approximately $2.8 million is included in other long-term liabilities at December 31, 2004.
At the end of the useful life of a well, the Company is required to remediate the site by plugging and abandoning the well. Costs associated with this obligation totaled $0.7 million, $1.3 million, and $0.7 million during the years ended December 31, 2004, 2003 and 2002, respectively.
Operating lease rentals for office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $5.6 million in 2004, $5.5 million in 2003 and $5.8 million in 2002. Future lease payments under non-cancelable operating leases as of December 31, 2004 totaled $66.9 million (2005 - $6.7 million, 2006 - $7.1 million, 2007 - $6.4 million, 2008 - $5.2 million, 2009 - $3.9 million and thereafter - $37.6 million).
23. Guarantees
In November 1995, the Company monetized certain Appalachian gas properties to a partnership, ABP, the production from which qualified for nonconventional fuels tax credits. As part of that transaction, Equitable, through a subsidiary guaranteed a tax indemnification to the limited partners for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes.
95
The periods ending December 31, 1997 are closed. As of December 31, 2004, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $46.0 million. As of December 31, 2004, the Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45), and has not been modified subsequent to issuance. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover any of the amounts paid under the guarantee.
In June 2000, Equitable sold properties with reserves of approximately 66.0 Bcfe, the production from which qualified for nonconventional fuels tax credits. As part of that transaction, Equitable, through a subsidiary guaranteed a tax indemnification to the buyer for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company guaranteed the tax indemnification until the tax statute of limitations closes. As of December 31, 2004, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $23.0 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN No. 45 and has not been modified subsequent to issuance.
In December 2000, the Company entered into a transaction with Appalachian Natural Gas Trust (ANGT) by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. ANGT manages the assets and produces, markets, and sells the related natural gas from the properties. ANPI contributed cash to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt. The Company provided ANPI with a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. This guarantee is subject to certain restrictions and limitations, as set forth in the guarantee agreement, as to the eligibility, amount and terms of the guarantee. These restrictions limit the amount of the guarantee to the calculated present value of the project’s future cash flows from the preceding year-end until the termination date of the agreement. The agreement also defines events of default, use of proceeds and demand procedures. The Company has received a market-based fee for providing the guarantee. As of December 31, 2004, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be $29 million. The Company has not recorded a liability for this guarantee, as the guarantee was issued prior to the effective date of FIN No. 45 and has not been modified subsequent to issuance.
A wholly owned subsidiary of the Company has provided two guarantees in support of a 50% owned, non-recourse financed energy project located in Panama. The guarantees represent 50% of the performance guarantee for the project’s principal Power Purchase Agreement and cover a project loan debt service reserve requirement. In the second quarter of 2004, the Company established a liability for the guarantees in the amount of $5.8 million. This $5.8 million was included as part of the entire impairment charge of $39.6 million, which has been included as international investments, primarily impairment on the Statement of Consolidated Income for the year ended December 31, 2004. See Note 9.
24. Insurance Settlement
On April 14, 2004, the Company settled a disputed property insurance coverage claim involving Kentucky West Virginia Gas Company, LLC, which is a part of the Supply segment. As a result of the settlement, the Company recognized income of approximately $6.1 million in the second quarter of 2004. The insurance proceeds are included in other income, net, in the Statement of Consolidated Income for the year ended December 31, 2004.
25. Renegotiation of Processing Agreement
On September 24, 2004, the Company renegotiated a processing agreement with one of its customers whereby the liquid processing agreement between the two parties was changed from a make-whole arrangement to a processing fee arrangement. As a result of this change, the Company recognized a net gain of $2.7 million, which is included in net operating revenues in the Statement of Consolidated Income for the year ended December 31, 2004.
96
26. Interim Financial Information (Unaudited)
The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company’s utility business and volatility of natural gas and oil commodity prices:
|
|
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
|
||||
|
|
|
(Thousands except per share amounts) |
|
||||||||||
|
2004 |
|
|
|
|
|
|
|
|
|
||||
|
Operating revenues |
|
$ |
400,427 |
|
$ |
240,640 |
|
$ |
205,847 |
|
$ |
344,695 |
|
|
Net operating revenues |
|
202,831 |
|
147,058 |
|
142,609 |
|
179,971 |
|
||||
|
Operating income |
|
119,527 |
|
47,157 |
|
64,527 |
|
73,440 |
|
||||
|
Income from continuing operations before cumulative effect of accounting change |
|
70,070 |
|
130,827 |
|
35,683 |
|
43,274 |
|
||||
|
Net income |
|
70,070 |
|
130,827 |
|
35,683 |
|
43,274 |
|
||||
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
||||
|
Income from continuing operations before cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
$ |
1.13 |
|
$ |
2.11 |
|
$ |
0.58 |
|
$ |
0.71 |
|
|
Diluted |
|
$ |
1.10 |
|
$ |
2.06 |
|
$ |
0.57 |
|
$ |
0.69 |
|
|
Net Income |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
$ |
1.13 |
|
$ |
2.11 |
|
$ |
0.58 |
|
$ |
0.71 |
|
|
Diluted |
|
$ |
1.10 |
|
$ |
2.06 |
|
$ |
0.57 |
|
$ |
0.69 |
|
|
2003 |
|
|
|
|
|
|
|
|
|
||||
|
Operating revenues |
|
$ |
342,322 |
|
$ |
218,496 |
|
$ |
185,515 |
|
$ |
300,944 |
|
|
Net operating revenues |
|
188,352 |
|
132,070 |
|
128,426 |
|
169,723 |
|
||||
|
Operating income |
|
109,320 |
|
56,817 |
|
54,177 |
|
81,903 |
|
||||
|
Income from continuing operations before cumulative effect of accounting change |
|
64,479 |
|
31,395 |
|
28,212 |
|
49,471 |
|
||||
|
Net income (a) |
|
60,923 |
|
31,395 |
|
28,212 |
|
49,471 |
|
||||
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
||||
|
Income from continuing operations before cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
$ |
1.04 |
|
$ |
0.51 |
|
$ |
0.45 |
|
$ |
0.80 |
|
|
Diluted |
|
$ |
1.02 |
|
$ |
0.50 |
|
$ |
0.45 |
|
$ |
0.78 |
|
|
Net Income |
|
|
|
|
|
|
|
|
|
||||
|
Basic |
|
$ |
0.98 |
|
$ |
0.51 |
|
$ |
0.45 |
|
$ |
0.80 |
|
|
Diluted |
|
$ |
0.96 |
|
$ |
0.50 |
|
$ |
0.45 |
|
$ |
0.78 |
|
(a) Net Income for the three months ended March 31, 2003 includes the negative cumulative effect of an accounting change related to the adoption of Statement No. 143.
97
27. Natural Gas Producing Activities (Unaudited)
The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Supply segment in accordance with SFAS No. 69, “Disclosures About Oil and Natural Gas Producing Activities.”
Production Costs
The following table presents the costs incurred relating to natural gas and oil production activities:
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
(Thousands) |
|
|||||||
|
At December 31: |
|
|
|
|
|
|
|
|||
|
Capitalized costs |
|
$ |
1,396,899 |
|
$ |
1,303,655 |
|
$ |
1,140,129 |
|
|
Accumulated depreciation and depletion |
|
488,742 |
|
450,761 |
|
406,399 |
|
|||
|
Net capitalized costs |
|
$ |
908,157 |
|
$ |
852,894 |
|
$ |
733,730 |
|
|
Costs incurred: |
|
|
|
|
|
|
|
|||
|
Property acquisition: |
|
|
|
|
|
|
|
|||
|
Proved properties |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
|
Unproved properties |
|
— |
|
— |
|
— |
|
|||
|
Land and leasehold maintenance |
|
846 |
|
824 |
|
847 |
|
|||
|
Development (a) |
|
91,489 |
|
125,962 |
|
114,341 |
|
|||
(a) Amounts include $55.9 million, $82.7 million, and $82.5 million of costs incurred during 2004, 2003 and 2002, respectively, to develop the Company’s proved undeveloped reserves. The Company estimates that its future total development costs will be comprised of a similar percentage of costs incurred to develop the Company’s proved undeveloped reserves.
Results of Operations for Producing Activities
The following table presents the results of operations related to natural gas and oil production:
|
|
|
2004 |
|
2003 |
|
2002 |
|
||||||
|
|
|
(Thousands) |
|
||||||||||
|
Revenues: |
|
|
|
|
|
|
|
||||||
|
Affiliated |
|
$ |
10,599 |
|
$ |
11,457 |
|
$ |
7,145 |
|
|||
|
Nonaffiliated |
|
305,387 |
|
251,150 |
|
218,568 |
|
||||||
|
Production costs |
|
43,274 |
|
35,687 |
|
27,111 |
|
||||||
|
Depreciation and depletion |
|
41,275 |
|
35,974 |
|
28,387 |
|
||||||
|
Income tax expense |
|
85,701 |
|
71,414 |
|
52,076 |
|
||||||
|
Results of operations from producing
activities |
|
$ |
145,736 |
|
$ |
119,532 |
|
$ |
118,139 |
|
|||
Reserve Information
The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers, which was reviewed by the independent consulting firm of Ryder Scott Company LP. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. All of the Company’s proved reserves are in the United States.
In February 2003, the Company sold approximately 500 of its low-producing wells, within two of its non-strategic districts in two separate transactions. The sales resulted in a decrease of 13 Bcfe of net reserves. The 500 wells produced an aggregate of approximately 1.0 Bcfe in 2002. Additionally, in February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million. These reserves were already incorporated into the 2002 reserve amounts.
98
|
|
|
2004 |
|
2003 |
|
2002 |
|
|
|
|
(Millions of Cubic Feet) |
|
||||
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
Beginning of year |
|
2,064,126 |
|
2,131,821 |
|
2,072,871 |
|
|
Revision of previous estimates |
|
56,392 |
|
(41,053 |
) |
44,099 |
|
|
Sale of natural gas in place |
|
— |
|
(7,146 |
) |
— |
|
|
Extensions, discoveries and other additions (a) |
|
54,247 |
|
49,926 |
|
82,022 |
|
|
Production |
|
(72,226 |
) |
(69,422 |
) |
(67,171 |
) |
|
End of year |
|
2,102,539 |
|
2,064,126 |
|
2,131,821 |
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
Beginning of year |
|
1,580,474 |
|
1,573,278 |
|
1,490,093 |
|
|
End of year |
|
1,625,295 |
|
1,580,474 |
|
1,573,278 |
|
|
|
|
2004 |
|
2003 |
|
2002 |
|
|
|
|
(Thousands of Barrels) |
|
||||
|
Oil |
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
Beginning of year |
|
550 |
|
1,432 |
|
1,563 |
|
|
Revision of previous estimates |
|
552 |
|
170 |
|
(4 |
) |
|
Sale of oil in place |
|
— |
|
(969 |
) |
— |
|
|
Production |
|
(83 |
) |
(83 |
) |
(127 |
) |
|
End of year |
|
1,019 |
|
550 |
|
1,432 |
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
Beginning of year |
|
550 |
|
1,432 |
|
1,563 |
|
|
End of year |
|
1,019 |
|
550 |
|
1,432 |
|
(a) Includes 17,246 MMcf, 31,755 MMcf, and 21,300 MMcf of proved developed reserve extensions, discoveries and other additions during 2004, 2003 and 2002, respectively, that were not previously classified as proved undeveloped. The remaining balance represents additional proved undeveloped reserves.
99
Standard Measure of Discounted Future Cash Flow
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at an arbitrary rate of 10%. Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows:
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||
|
|
|
(Thousands) |
|
|||||||
|
Future cash inflows |
|
$ |
17,312,818 |
|
$ |
10,462,523 |
|
$ |
9,180,390 |
|
|
Future production costs |
|
(2,465,681 |
) |
(1,938,827 |
) |
(1,529,713 |
) |
|||
|
Future development costs |
|
(409,141 |
) |
(341,116 |
) |
(381,667 |
) |
|||
|
Future net cash flow before income taxes |
|
14,437,996 |
|
8,182,580 |
|
7,269,010 |
|
|||
|
10% annual discount for estimated timing of cash flows |
|
(9,736,734 |
) |
(5,550,907 |
) |
(5,037,625 |
) |
|||
|
Discounted future net cash flows before income taxes |
|
4,701,262 |
|
2,631,673 |
|
2,231,385 |
|
|||
|
Future income tax expenses, discounted at 10% annually |
|
(1,740,878 |
) |
(921,086 |
) |
(780,985 |
) |
|||
|
Standardized measure of discounted future net cash flows |
|
$ |
2,960,384 |
|
$ |
1,710,587 |
|
$ |
1,450,400 |
|
Summary of changes in the standardized measure of discounted future net cash flows:
|
|
|
2004 |
|
2003 |
|
2002 |
|
|||||
|
|
|
(Thousands) |
|
|||||||||
|
Sales and transfers of natural gas and oil produced – net |
|
$ |
(273,558 |
) |
$ |
(227,745 |
) |
$ |
(199,449 |
) |
||
|
Net changes in prices, production and development costs |
|
1,746,284 |
|
413,043 |
|
720,238 |
|
|||||
|
Extensions, discoveries and improved recovery, less related costs |
|
121,051 |
|
63,645 |
|
85,508 |
|
|||||
|
Development costs incurred |
|
68,688 |
|
70,112 |
|
69,267 |
|
|||||
|
Sale of minerals in place – net |
|
— |
|
(12,659 |
) |
— |
|
|||||
|
Revisions of previous quantity estimates |
|
131,142 |
|
(111,228 |
) |
103,734 |
|
|||||
|
Accretion of discount |
|
263,166 |
|
221,873 |
|
130,813 |
|
|||||
|
Net change in income taxes |
|
(819,792 |
) |
(140,101 |
) |
(323,140 |
) |
|||||
|
Other |
|
12,816 |
|
(16,753 |
) |
13,146 |
|
|||||
|
Net increase (decrease) |
|
1,249,797 |
|
260,187 |
|
600,117 |
|
|||||
|
Beginning of year |
|
1,710,587 |
|
1,450,400 |
|
850,283 |
|
|||||
|
End of year |
|
$ |
2,960,384 |
|
$ |
1,710,587 |
|
$ |
1,450,400 |
|
||
28. Subsequent Events
In January 2005, the Company repurchased the remaining 99% limited partnership interest in Eastern Seven Partners L.P. for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves.
Also in January 2005, the Company sold its interest in Compania Hidroelectrica Dona Julia, S.D.R. Ltd., a Costa Rican electric generation project, to a third party purchaser and recorded a slight gain on the sale in 2005.
100
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report. There were no significant changes in internal control over financial reporting (as defined in Rule 13a-15f under the Exchange Act) that occurred during the fourth quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
The management of Equitable is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)). Equitable’s internal control system is designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
Equitable’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. 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 the Company maintained effective internal control over financial reporting as of December 31, 2004.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young, LLP, the independent registered public accounting firm that also audited the Company’s consolidated financial statements. Ernst & Young’s attestation report on management’s assessment of the Company’s internal control over financial reporting appears in Part II, Item 8 of this Annual Report on Form 10-K and is incorporated by reference herein.
Not Applicable.
101
Item 10. Directors and Executive Officers of the Registrant
The following information is incorporated herein by reference from the Company’s definitive proxy statement relating to the annual meeting of the shareholders to be held on April 13, 2005, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2004:
• Information required by Item 401 of Regulation S-K with respect to directors is incorporated herein by reference from the section captioned “Item No. 1 - Election of Directors” in the Company’s definitive proxy statement;
• Information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Exchange Act is incorporated by reference from the section captioned “Stock Ownership and Performance – Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement;
• The information required by Item 401 of Regulation S-K with respect to disclosure of audit committee financial expert is incorporated herein by reference from the section captioned “Corporate Governance – Committees of the Board” in the Company’s definitive proxy statement; and
• The information required by Item 401 of Regulation S-K with respect to the identification of the Audit Committee is incorporated by reference from the section captioned “Corporate Governance – Committees of the Board” in the Company’s definitive proxy statement.
Information required by Item 401 of Regulation S-K with respect to executive officers is included herein after Item 4 at the end of Part I of Form 10-K under the heading “Executive Officers of the Registrant (as of February 25, 2005),” and is incorporated herein by reference.
The Company has adopted a code of ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. The code of ethics is posted on the Company’s website, www.eqt.com (under the “Corporate Governance” caption of the Investor Relations page) and a printed copy will be delivered to anyone who so requests by writing to the corporate secretary at Equitable Resources, Inc., c/o corporate secretary, One Oxford Centre, 301 Grant Street, Suite 3300, Pittsburgh, Pennsylvania 15219. Effective May 2005, the Company’s address will be 225 North Shore Drive, Pittsburgh, PA 15212. The Company intends to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of its code of ethics by posting such information on the Company’s website.
By certification dated April 23, 2004, the Company’s Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of NYSE corporate governance listing standards.
Item 11. Executive Compensation
Information required by Item 11 is incorporated herein by reference from the sections describing “Executive Compensation” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 13, 2005, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2004.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference to the sections captioned “Stock Ownership and Performance - - Significant Shareholders” and “Stock Ownership and Performance - Stock Ownership of Directors and Executive Officers” in the Company’s definitive proxy statement relating to the annual meeting of shareholders to be held on April 13, 2005, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2004.
The following table provides information as of December 31, 2004 with respect to shares of Equitable common stock that may be issued under the company’s existing equity compensation plans, including the 1999
102
Long-Term Incentive Plan, the 1994 Long-Term Incentive Plan, the 1999 Non-Employee Directors’ Stock Incentive Plan, the Employee Deferred Compensation Plan, the Directors’ Deferred Compensation Plan, and the Employee Stock Purchase Plan (each as amended through December 31, 2004).
|
Plan Category |
|
Number Of |
|
Weighted Average |
|
Number Of Securities |
|
|
|
Equity Compensation Plans Approved by Shareholders (1) |
|
4,102,139 |
(3) |
$ |
27.00 |
(3) |
4,964,116 |
|
|
|
|
|
|
|
|
|
|
|
|
Equity Compensation Plans Not Approved by Shareholders (2) |
|
122,723 |
|
$ |
15.99 |
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
4,224,862 |
(3) |
$ |
26.68 |
(3) |
4,964,116 |
|
|
|
|
|
|
|
|
|
|
|
(1) Includes the 1994 Long-Term Incentive Plan as to which grants may no longer be made, the 1999 Long-Term Incentive Plan, the 1999 Non-Employee Directors’ Stock Incentive Plan and the Employee Stock Purchase Plan.
(2) Includes the Employee Deferred Compensation Plan under which deferrals may no longer be made and 38,740 shares issuable under the Directors’ Deferred Compensation Plan in connection with a 1999 grant payable in common stock of Equitable Resources. The Employee Deferred Compensation Plan and the Directors’ Deferred Compensation Plan are described below. Also described below are the 2005 Employee Deferred Compensation Plan and the 2005 Directors’ Deferred Compensation Plan (the 2005 Plans) which are not included in the chart above because they were adopted effective January 1, 2005. Had the 2005 Plans been in effect on December 31, 2004, there would be zero additional shares in Column A and 100,000 additional shares in Column C.
(3) Excludes purchase rights accruing under the Employee Stock Purchase Plan, which has a 1,000,000 share shareholder-approved maximum of which 879,120 shares remain available for issuance.
The Employee Deferred Compensation Plan was suspended as of December 31, 2004. After December 31, 2004, the Employee Deferred Compensation Plan will, however, continue to operate for the sole purpose of administering vested amounts deferred under the plan on or prior to December 31, 2004. The plan allowed key employees to defer all or a portion of their base salary and bonus and other income from the company. Under the plan, the company matched, in company stock, on a basis consistent with the company’s 401(k) plans, a deferral election by an employee of base salary and bonus. Amounts deferred are payable upon an employee’s separation from service, disability or death, unless the employee elected an in-service distribution prior to earning such amount or an early payment is authorized after the employee suffers an unforeseeable financial emergency.
The 2005 Employee Deferred Compensation Plan was adopted by the Compensation Committee of the Board of Directors and became effective on January 1, 2005. The plan did not require approval by shareholders. The plan allows key employees to defer a portion of their base salary over the compensation limit provided in the Internal Revenue Code, all of their bonus, and other cash awards or grants of restricted stock (prior to award) from the company. Under the plan, the company matches, in company stock, on a basis consistent with the company’s 401(k) plans, a deferral election of base salary and bonus. Amounts deferred are payable upon an employee’s separation from service, disability or death, unless an early payment is authorized after the employee suffers an unforeseeable financial emergency.
103
The Directors’ Deferred Compensation Plan was suspended as of December 31, 2004. After December 31, 2004, the Directors’ Deferred Compensation Plan will, however, continue to operate for the sole purpose of administering vested amounts deferred under the plan on or prior to December 31, 2004. The plan allowed non-employee directors of the company to defer all or a portion of their directors’ fees and retainer. In 1999 the Board approved a one-time grant of 38,740 phantom shares which is payable in company stock and was deferred under the plan. No other equity compensation grants have been made under the Directors’ Deferred Compensation Plan. Deferred amounts are generally payable upon retirement from the Board, but may be payable earlier upon election of the applicable director prior to the earning of such amount or an early payment is authorized after a director suffers an unforeseeable financial emergency. In addition to deferred directors’ fees and retainers, the phantom stock units granted to directors prior to January 1, 2005 under the 1999 Non-Employee Directors’ Stock Incentive Plan are administered under this plan.
The 2005 Directors’ Deferred Compensation Plan was adopted by the Compensation Committee of the Board of Directors and became effective on January 1, 2005. The plan did not require approval by shareholders. The Plan allows non-employee directors to defer all or a portion of their directors’ fees and retainer. Amounts deferred are payable upon retirement from the Board unless an early payment is authorized after the director suffers an unforeseeable financial emergency. In addition to deferred directors’ fees and retainers, the phantom stock units granted to directors on or after January 1, 2005 under the 1999 Non-Employee Directors’ Stock Incentive Plan are administered under this plan.
Item 13. Certain Relationships and Related Transactions
None.
Item 14. Principal Accountant Fees and Services
Information required by Item 14 is incorporated herein by reference to the section captioned “Item No. 2 – Ratification of Appointment of Independent Registered Public Accounting Firm” in the Company’s definitive proxy statement relating to the annual meeting of stockholders to be held on April 13, 2005, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2004.
104
Item 15. Exhibits, Financial Statement Schedules
(a) 1. Financial Statements
The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.
2. Financial Statement Schedule
The financial statement schedule listed in the accompanying index to financial statements and financial schedule is filed as part of this Annual Report on Form 10-K.
3. Exhibits
The exhibits listed on the accompanying index to exhibits (pages 107 through 112) are filed as part of this Annual Report on Form 10-K.
EQUITABLE RESOURCES, INC.
INDEX TO FINANCIAL
STATEMENTS COVERED
BY REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
(Item 15 (a))
1. |
The following consolidated financial statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8: |
Statements of Consolidated Income for each of the three years in the period ended December 31, 2004 |
|
|
|
|
|
|
||
|
|
|
Consolidated Balance Sheets as of December 31, 2004 and 2003 |
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
2. |
Schedule for the Years Ended December 31, 2004, 2003 and 2002 included in Part IV: |
|
|
All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules. |
105
EQUITABLE RESOURCES, INC. AND
SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
|
Column A |
|
Column B |
|
Column C |
|
Column D |
|
Column E |
|
|||||||
|
Description |
|
Balance at |
|
Additions |
|
Additions |
|
Deductions |
|
Balance at |
|
|||||
|
|
|
(Thousands) |
|
|||||||||||||
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Accumulated provisions for doubtful accounts |
|
$ |
18,041 |
|
$ |
19,390 |
|
$ |
3,332 |
(b) |
$ |
9,427 |
|
$ |
31,336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Accumulated provisions for doubtful accounts |
|
$ |
15,294 |
|
$ |
13,697 |
|
$ |
— |
|
$ |
10,950 |
|
$ |
18,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
2002 |
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Accumulated provisions for doubtful accounts |
|
$ |
14,807 |
|
$ |
8,564 |
|
$ |
— |
|
$ |
8,077 |
|
$ |
15,294 |
|
Note:
(a) Customer accounts written off, less recoveries.
(b) Represents $3.3 million for Energy Assistance Program surcharge reserve.
106
|
Exhibits |
|
Description |
|
Method of Filing |
|
3.01 |
|
Restated Articles of Incorporation of the Company dated May 1, 2001 |
|
Filed as Exhibit 3.01 to Form 10-K for the year ended December 31, 2002 |
|
|
|
|
|
|
|
3.02 |
|
Bylaws of the Company (amended through January 12, 2005) |
|
Filed as Exhibit 3.01 to Form 8-K filed on February 10, 2005 |
|
|
|
|
|
|
|
4.01 (a) |
|
Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank |
|
Filed as Exhibit 4.1 to Registration Statement on From S-3 filed April 24, 1986 (Registration No. 2-80575) |
|
|
|
|
|
|
|
4.01 (b) |
|
Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank |
|
Filed as Exhibit 4.01 (b) to Form 10-K for the year ended December 31, 1998 |
|
|
|
|
|
|
|
4.01 (c) |
|
Supplemental Indenture dated March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt |
|
Filed as Exhibit 4.01 (f) to Form 10-K for the year ended December 31, 1996 |
|
|
|
|
|
|
|
4.01 (d) |
|
Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes |
|
Filed as Exhibit 4.01 (g) to Form 10-K for the year ended December 31, 1996 |
|
|
|
|
|
|
|
4.01 (e) |
|
Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes |
|
Refiled as Exhibit 4.01 (h) to Form 10-K for the year ended December 31, 1997 |
|
|
|
|
|
|
|
4.01 (f) |
|
Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes |
|
Filed as Exhibit 4.01 (i) to Form 10-K for the year ended December 31, 1995 |
|
|
|
|
|
|
|
4.02 (a) |
|
Indenture with The Bank of New York, as successor to Bank of Montreal Trust Company, a Trustee, dated as of July 1, 1996 |
|
Filed as Exhibit 4.01 (a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
107
|
Exhibits |
|
Description |
|
Method of Filing |
|
4.02 (b) |
|
Resolution adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolutions adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996 |
|
Filed as Exhibit 4.01 (j) to Form 10-K for the year ended December 31, 1996 |
|
|
|
|
|
|
|
4.02 (c) |
|
Resolutions adopted January 16, 2003 by the Board of Directors establishing the terms of the offering of up to $200,000,000 aggregate principal amount of 5.15% Notes due 2018 |
|
Filed as Exhibit 4.01 (b) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003 |
|
|
|
|
|
|
|
4.02 (d) |
|
Officer’s Declaration dated February 20, 2003 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000 |
|
Filed as Exhibit 4.01 (c) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003 |
|
|
|
|
|
|
|
4.02 (e) |
|
Officer’s Certificate dated February 27, 2003 certifying the terms and form of the Notes in an aggregate amount of up to $200,000,000 |
|
Filed as Exhibit 4.01 (d) to Form S-4 Registration Statement (#333-104392) filed on April 8, 2003 |
|
|
|
|
|
|
|
4.02 (f) |
|
Resolutions adopted October 17, 2002 by the Board of Directors establishing the terms of the offering of up to $200,000,000 aggregate principal amount of 5.15% Notes Due 2012 |
|
Filed as Exhibit 4.01 (b) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003 |
|
|
|
|
|
|
|
4.02 (g) |
|
Officer’s Declaration dated November 7, 2002 establishing the terms of the issuance and sale of the Notes of the Company in an aggregate amount of up to $200,000,000 |
|
Filed as Exhibit 4.01 (c) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003 |
|
|
|
|
|
|
|
4.02 (h) |
|
Officer’s Certificate dated November 15, 2002 certifying the terms and form of the Notes in an aggregate amount of up to $200,000,000 |
|
Filed as Exhibit 4.01 (d) to Form S-4/A Registration Statement (#333-103178) filed on March 12, 2003 |
|
|
|
|
|
|
|
4.03 |
|
Amended and Restated Rights Agreement dated as of January 23, 2004 between the Company and Mellon Investor Services, LLC, as Rights Agent, setting forth the amended and restated terms of the Company’s Preferred Stock Purchase Rights Plan |
|
Filed as Exhibit 1 to Registration Statement on Form 8-A/A filed January 29, 2004 |
|
|
|
|
|
|
|
4.04 (a) |
|
Equitable Resources, Inc. $500,000,000 Revolving Credit Agreement dated October 30, 2003 |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2003 |
|
|
|
|
|
|
|
4.04 (b) |
|
First Amendment to Equitable Resources, Inc. $500,000,000 Revolving Credit Agreement dated October 30, 2003 (amended June 16, 2004) |
|
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 2004 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
108
|
Exhibits |
|
Description |
|
Method of Filing |
|
10.01 |
|
Termination Agreement, dated as of April 6, 2004, by and among Westport Resources Corporation, Westport Energy LLC, EQT Investments LLC (a successor-in-interest to ERI Investments, Inc.), Medicor Foundation, and certain stockholders named therein |
|
Filed as Exhibit 10.1 to amendment No. 5 of Schedule 13D dated April 13, 2004 |
|
|
|
|
|
|
|
10.02 |
|
Voting Agreement, dated as of April 6, 2004, by and among Kerr-McGee Corporation and each stockholder named on schedule 1 thereto |
|
Filed as Exhibit 10.2 to amendment No. 5 of Schedule 13D dated April 13, 2004 |
|
|
|
|
|
|
|
10.03 |
|
Registration Rights Agreement, dated as of April 6, 2004, by and among Kerr-McGee Corporation, Westport Energy LLC, EQT Investments, LLC (a successor-in-interest to ERI Investments, Inc.), Medicor Foundation, and certain stockholders named therein |
|
Filed as Exhibit 10.3 to amendment No. 5 of Schedule 13D dated April 13, 2004 |
|
|
|
|
|
|
|
* 10.04 |
|
1999 Equitable Resources, Inc. Long-Term Incentive Plan (amended and restated October 20, 2004) |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004 |
|
|
|
|
|
|
|
* 10.05 |
|
Form of Participant Award Agreement (Restricted Stock) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Filed herewith as Exhibit 10.05 |
|
|
|
|
|
|
|
* 10.06 |
|
Form of Participant Award Agreement (Stock Option) under 1999 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2004 |
|
|
|
|
|
|
|
* 10.07 |
|
1994 Equitable Resources, Inc. Long-Term Incentive Plan |
|
Refiled as Exhibit 10.06 to Form 10-K for the year ended December 31, 1999 |
|
|
|
|
|
|
|
* 10.08 |
|
Equitable Resources, Inc. Breakthrough Long-Term Incentive Plan with certain executives of the Company (as amended) |
|
Filed as Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2000 |
|
|
|
|
|
|
|
* 10.09 |
|
1999 Equitable Resources, Inc. Non-Employee Directors’ Stock Incentive Plan (as amended May 26, 1999) |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 1999 |
|
|
|
|
|
|
|
* 10.10 |
|
Equitable Resources, Inc. Executive Short-Term Incentive Plan |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2001 |
|
|
|
|
|
|
|
* 10.11 |
|
Equitable Resources, Inc. 2002 Short-Term Incentive Plan |
|
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2002 |
|
|
|
|
|
|
|
* 10.12 |
|
Equitable Resources, Inc. 2003 Short-Term Incentive Plan |
|
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2003 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
109
|
Exhibits |
|
Description |
|
Method of Filing |
|
* 10.13 |
|
Equitable Resources, Inc. 2004 Short-Term Incentive Plan |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2004 |
|
|
|
|
|
|
|
* 10.14 |
|
Equitable Resources, Inc. 2005 Short-Term Incentive Plan |
|
Filed as Exhibit 10.1 to Form 8-K filed on December 6, 2004 |
|
|
|
|
|
|
|
* 10.15 |
|
Equitable Resources, Inc. 2002 Executive Performance Incentive Program (as amended and restated May 1, 2003 and April 13, 2004) |
|
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 20, 2004 |
|
|
|
|
|
|
|
* 10.16 |
|
Form of Participant Award Agreement under the Equitable Resources, Inc. 2002 Executive Performance Incentive Program |
|
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004 |
|
|
|
|
|
|
|
* 10.17 |
|
Equitable Resources, Inc. 2003 Executive Performance Incentive Program (as amended and restated April 13, 2004) |
|
Filed as Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2004 |
|
|
|
|
|
|
|
* 10.18 |
|
Form of Participant Award Agreement under the Equitable Resources, Inc. 2003 Executive Performance Incentive Program |
|
Filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2004 |
|
|
|
|
|
|
|
* 10.19 |
|
Equitable Resources, Inc. Directors’ Deferred Compensation Plan (as amended and restated May 15, 2003) |
|
Filed as Exhibit 10.10 to Form 10-Q for the quarter ended June 30, 2003 |
|
|
|
|
|
|
|
* 10.20 |
|
Equitable Resources, Inc. 2005 Directors’ Deferred Compensation Plan |
|
Filed as Exhibit 10.2 to Form 8-K filed on December 28, 2004 |
|
|
|
|
|
|
|
* 10.21 |
|
Equitable Resources, Inc. Employee Deferred Compensation Plan (amended and restated effective December 3, 2003) |
|
Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 2003 |
|
|
|
|
|
|
|
* 10.22 |
|
Equitable Resources, Inc. 2005 Employee Deferred Compensation Plan |
|
Filed as Exhibit 10.1 to Form 8-K filed on December 28, 2004 |
|
|
|
|
|
|
|
* 10.23 (a) |
|
Employment Agreement dated as of May 4, 1998 with Murry S. Gerber |
|
Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 1998 |
|
|
|
|
|
|
|
* 10.23 (b) |
|
Amendment No. 1 to Employment Agreement with Murry S. Gerber |
|
Filed as Exhibit 10.09 (b) to Form 10-K for the year ended December 31, 1999 |
|
|
|
|
|
|
|
* 10.23 (c) |
|
Amendment No. 2 to Employment Agreement with Murry S. Gerber |
|
Filed as Exhibit 10.09 (c) to Form 10-Q for the quarter ended September 30, 2002 |
|
|
|
|
|
|
|
* 10.23 (d) |
|
Amendment No. 3 to Employment Agreement with Murry S. Gerber |
|
Filed as Exhibit 10.13 (d) to Form 10-K for the year ended December 31, 2003 |
|
|
|
|
|
|
|
* 10.23 (e) |
|
Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Murry S. Gerber |
|
Filed as Exhibit 10.10 to Form 10-Q for the quarter ended September 30, 2002 |
|
|
|
|
|
|
|
* 10.23 (f) |
|
Supplemental Executive Retirement Agreement dated as of May 4, 1998 with Murry S. Gerber |
|
Filed as Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 1998 |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
110
|
Exhibits |
|
Description |
|
Method of Filing |
|
* 10.23 (g) |
|
Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with Murry S. Gerber |
|
Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 1999 |
|
|
|
|
|
|
|
* 10.24 (a) |
|
Employment Agreement dated as of July 1, 1998 with David L. Porges |
|
Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 1998 |
|
|
|
|
|
|
|
* 10.24 (b) |
|
Amendment No. 1 to Employment Agreement with David L. Porges |
|
Filed as Exhibit 10.13 (b) to Form 10-K for the year ended December 31, 1999 |
|
|
|
|
|
|
|
* 10.24 (c) |
|
Amendment No. 2 to Employment Agreement with David L. Porges |
|
Filed as Exhibit 10.13 (c) to Form 10-Q for the quarter ended September 30, 2002 |
|
|
|
|
|
|
|
* 10.24 (d) |
|
Amendment No. 3 to Employment Agreement with David L. Porges |
|
Filed as Exhibit 10.14 (d) to Form 10-K for the year ended December 31, 2003 |
|
|
|
|
|
|
|
* 10.24 (e) |
|
Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and David L. Porges |
|
Filed as Exhibit 10.14 to Form 10-Q for the quarter ended September 30, 2002 |
|
|
|
|
|
|
|
* 10.24 (f) |
|
Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with David L. Porges |
|
Filed as Exhibit 10.15 to Form 10-K for the year ended December 31, 1999 |
|
|
|
|
|
|
|
* 10.25 (a) |
|
Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Johanna G. O’Loughlin |
|
Filed as Exhibit 10.18 to Form 10-Q for the quarter ended September 30, 2002 |
|
|
|
|
|
|
|
* 10.25 (b) |
|
Noncompete Agreement dated December 1, 1999 with Johanna G. O’Loughlin |
|
Filed as Exhibit 10.19 to Form 10-K for the year ended December 31, 1999 |
|
|
|
|
|
|
|
* 10.25 (c) |
|
Release re: Split Dollar Life Insurance |
|
Filed as Exhibit 10.15 (c) to Form 10-K for the year ended December 31, 2003 |
|
|
|
|
|
|
|
* 10.26 (a) |
|
Change in Control Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and John A. Bergonzi |
|
Filed herewith as Exhibit 10.26 (a) |
|
|
|
|
|
|
|
* 10.26 (b) |
|
Non-Compete Agreement dated December 1, 1999 by and between Equitable Resources, Inc. and John A. Bergonzi |
|
Filed herewith as Exhibit 10.26 (b) |
|
|
|
|
|
|
|
* 10.27 (a) |
|
Change in Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Philip P. Conti |
|
Filed as Exhibit 10.26 to Form 10-Q for the quarter ended September 30, 2002 |
|
|
|
|
|
|
|
* 10.27 (b) |
|
Non-Compete Agreement dated October 30, 2000 by and between Equitable Resources, Inc. and Philip P. Conti |
|
Filed herewith as Exhibit 10.27 (b) |
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
111
|
Exhibits |
|
Description |
|
Method of Filing |
|
* 10.28 (a) |
|
Agreement dated May 24, 1996 with Phyllis A. Domm for deferred payment of 1996 director fees beginning May 24, 1996 |
|
Filed as Exhibit 10.14 (a) to Form 10-K for the year ended December 31, 1996 |
|
|
|
|
|
|
|
* 10.28 (b) |
|
Agreement dated November 27, 1996 with Phyllis A. Domm for deferred payment of 1997 director fees |
|
Filed as Exhibit 10.14 (b) to Form 10-K for the year ended December 31, 1996 |
|
|
|
|
|
|
|
* 10.28 (c) |
|
Agreement dated November 30, 1997 with Phyllis A. Domm for deferred payment of 1998 director fees |
|
Filed as Exhibit 10.14 (c) to Form 10-K for the year ended December 31, 1997 |
|
|
|
|
|
|
|
* 10.28 (d) |
|
Agreement dated December 5, 1998 with Phyllis A. Domm for deferred payment of 1999 director fees |
|
Filed as Exhibit 10.20 (d) to Form 10-K for the year ended December 31, 1998 |
|
|
|
|
|
|
|
* 10.29 |
|
Form of Indemnification Agreement between Equitable Resources, Inc. and all executive officers and outside directors |
|
Filed as Exhibit 10.41 to Form 10-K for the year ended December 31, 2002 |
|
|
|
|
|
|
|
* 10.30 |
|
Directors’ Compensation and Retirement Program |
|
Filed herewith as Exhibit 10.30 |
|
|
|
|
|
|
|
21 |
|
Schedule of Subsidiaries |
|
Filed herewith as Exhibit 21 |
|
|
|
|
|
|
|
23.01 |
|
Consent of Independent Registered Public Accounting Firm |
|
Filed herewith as Exhibit 23.01 |
|
|
|
|
|
|
|
23.02 |
|
Consent of Independent Petroleum Engineers |
|
Filed herewith as Exhibit 23.02 |
|
|
|
|
|
|
|
31.1 |
|
Certification of Murry S. Gerber, Chief Executive Officer of Equitable Resources, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith as Exhibit 31.1 |
|
|
|
|
|
|
|
31.2 |
|
Certification of David L. Porges, Executive Vice President, Finance and Administration of Equitable Resources, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith as Exhibit 31.2 |
|
|
|
|
|
|
|
32 |
|
Certification of Murry S. Gerber, Chief Executive Officer of Equitable Resources, Inc., David L. Porges, Executive Vice President, Finance and Administration (Principal Financial Officer) of Equitable Resources, Inc., and Philip P. Conti, Vice President, Chief Financial Officer and Treasurer of Equitable Resources, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
Filed herewith as Exhibit 32 |
The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt, which have not previously been filed.
Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).
112
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.
|
|
|
EQUITABLE RESOURCES, INC. |
|
|
|
|
|
|
By: |
/s/ MURRY S. GERBER |
|
|
|
Murry S. Gerber |
|
|
|
Chairman, President and Chief Executive Officer |
|
|
|
February 23, 2005 |
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.
|
/s/ MURRY S. GERBER |
|
Chairman, President and |
|
February 23, 2005 |
|
Murry S. Gerber |
|
Chief Executive Officer |
|
|
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
|
|
|
|
/s/ DAVID L. PORGES |
|
Vice Chairman and Executive |
|
February 23, 2005 |
|
David L. Porges |
|
Vice President, Finance and |
|
|
|
(Principal Financial Officer) |
|
Administration |
|
|
|
|
|
|
|
|
|
/s/ JOHN A. BERGONZI |
|
Vice President and |
|
February 23, 2005 |
|
John A. Bergonzi |
|
Corporate Controller |
|
|
|
(Principal Accounting Officer) |
|
|
|
|
|
|
|
|
|
|
|
/s/ VICKY A. BAILEY |
|
Director |
|
February 23, 2005 |
|
Vicky A. Bailey |
|
|
|
|
|
|
|
|
|
|
|
/s/ PHYLLIS A. DOMM |
|
Director |
|
February 23, 2005 |
|
Phyllis A. Domm |
|
|
|
|
|
|
|
|
|
|
|
/s/ BARBARA S. JEREMIAH |
|
Director |
|
February 23, 2005 |
|
Barbara S. Jeremiah |
|
|
|
|
|
|
|
|
|
|
|
/s/ THOMAS A. MCCONOMY |
|
Director |
|
February 23, 2005 |
|
Thomas A. McConomy |
|
|
|
|
|
|
|
|
|
|
|
/s/ GEORGE L. MILES, JR. |
|
Director |
|
February 23, 2005 |
|
George L. Miles, Jr. |
|
|
|
|
|
|
|
|
|
|
|
/s/ JAMES E. ROHR |
|
Director |
|
February 23, 2005 |
|
James E. Rohr |
|
|
|
|
|
|
|
|
|
|
|
/s/ DAVID S. SHAPIRA |
|
Director |
|
February 23, 2005 |
|
David S. Shapira |
|
|
|
|
|
|
|
|
|
|
|
/s/ LEE T. TODD, JR. |
|
Director |
|
February 23, 2005 |
|
Lee T. Todd, Jr. |
|
|
|
|
|
|
|
|
|
|
|
/s/ JAMES W. WHALEN |
|
Director |
|
February 23, 2005 |
|
James W. Whalen |
|
|
|
|
113