1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 [ ] 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) <TABLE> <S> <C> PENNSYLVANIA 25-0464690 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) ONE OXFORD CENTRE, SUITE 3300 PITTSBURGH, PENNSYLVANIA 15219 (Address of principal executive offices) (Zip Code) </TABLE> Registrant's telephone number, including area code: (412) 553-5700 Securities registered pursuant to Section 12(b) of the Act: <TABLE> <CAPTION> NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- ----------------------------- <S> <C> Common Stock, no par value New York Stock Exchange Philadelphia Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange Philadelphia Stock Exchange 7.35% Capital Securities due April 15, 2038 New York Stock Exchange </TABLE> 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 X No __ 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 of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of voting stock held by non-affiliates of the registrant as of February 29, 2000: $1,218,817,565 The number of shares outstanding of the issuer's classes of common stock as of February 29, 2000: 32,800,787 DOCUMENTS INCORPORATED BY REFERENCE Part III, a portion of Item 10 and Items 11, 12 and 13 are incorporated by reference to the Proxy Statement for the Annual Meeting of Stockholders on May 17, 2000 to be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 1999. Index to Exhibits -- Page 63
2 TABLE OF CONTENTS <TABLE> <CAPTION> PAGE ---- <S> <C> <C> PART I Item 1 Business.................................................... 3 Item 2 Properties.................................................. 8 Item 3 Legal Proceedings........................................... 9 Item 4 Submission of Matters to a Vote of Security Holders......... 10 Executive Officers of the Registrant........................ 11 PART II Item 5 Market for Registrant's Common Equity and Related Stockholder Matters....................................... 12 Item 6 Selected Financial Data..................................... 12 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations..................................... 13 Item 7A Qualitative and Quantitative Disclosures About Market Risk...................................................... 29 Item 8 Financial Statements and Supplementary Data................. 30 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................... 59 PART III Item 10 Directors and Executive Officers of the Registrant.......... 60 Item 11 Executive Compensation...................................... 60 Item 12 Security Ownership of Certain Beneficial Owners and Management................................................ 60 Item 13 Certain Relationships and Related Transactions.............. 60 PART IV Item 14 Exhibits and Reports on Form 8-K............................ 61 Index to Financial Statements Covered by Report of Independent Auditors...................................... 61 Index to Exhibits........................................... 63 Signatures.................................................. 67 </TABLE>
3 PART I ITEM 1. BUSINESS Equitable Resources, Inc. (Equitable or the Company) is an integrated energy company, with emphasis on Appalachian area natural gas production and transportation, natural gas distribution and transmission, and energy services marketing in the northeastern section of the United States. The Company also has exploration and production interests in the Gulf of Mexico and energy service management projects in selected U.S. and international markets. The Company and its subsidiaries offer energy (natural gas, natural gas liquids and crude oil) products and services to wholesale and retail customers through three primary business segments: Equitable Utilities, Equitable Production and NORESCO. The Company and its subsidiaries had 1,620 employees at the end of 1999. 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. to more appropriately reflect the Company's transition from a regulated utility to an integrated energy company. EQUITABLE UTILITIES Equitable Utilities contains both regulated and nonregulated operations. The regulated group consists of the distribution and interstate pipeline operations, while the unregulated group is involved in nonjurisdictional marketing of natural gas and risk management activities. Equitable Utilities generated 50 percent of the Company's net operating revenues in 1999. NATURAL GAS DISTRIBUTION Equitable Utilities' distribution operations are conducted by Equitable Gas Company (Equitable Gas), a division of the Company, and Carnegie Natural Gas Company (Carnegie Natural Gas or Carnegie), acquired on December 15, 1999. The service territory for Equitable Gas and Carnegie Natural Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales in eastern Kentucky. The distribution operations provide natural gas services to more than 274,000 customers, comprising 256,000 residential customers and 18,000 commercial and industrial customers. Equitable Gas' natural gas portfolio includes short-term, medium-term and long-term natural gas supply contracts. Most natural gas is purchased from Southwest suppliers and transported by either Texas Eastern Transmission Corporation or Tennessee Gas Pipeline Company. A smaller percentage of natural gas is purchased from production properties in Kentucky owned by Equitable Production and transported by Columbia Gas Transmission Company. Because many of its customers use natural gas for heating purposes, Equitable Gas's revenues are seasonal, with approximately 68% of calendar year 1999 revenues occurring during the winter heating season from November through March. Significant quantities of purchased natural gas are placed in underground storage inventory during the off-peak season to accommodate higher customer demand during the winter heating season. Competition in markets served by Equitable Gas is expected to continue. Equitable Gas faces price competition with other energy forms. In addition, with unbundling of natural gas sales from natural gas distribution and transmission in the natural gas industry, competition is increasing to provide natural gas sales to commercial and residential customers. Unregulated natural gas marketers have been selling natural gas to commercial and industrial customers in Equitable Gas's service territory for over 20 years and Equitable Gas has provided transportation services to those customers through contract. Large customers have been able to select individually or in combination the various natural gas supply, storage and/or transportation services they require. Equitable Gas has responded to this competitive environment by offering a variety of firm and interruptible services, including natural gas transportation, supply pooling, balancing and brokering, to industrial and commercial customers. 3
4 On April 1, 1998, Equitable Gas began to offer "unbundled" service to all of its customers in Pennsylvania, allowing them to choose their natural gas supplier. Revenues derived from transportation charges on natural gas sold by other suppliers enable Equitable Gas to minimize economic loss resulting from the switching of residential customers to other suppliers. Because the margin on natural gas bundled sales approximates the margin received on transportation-only volumes, Equitable Gas is neutral as to whether it provides transportation or bundled sales to retail customers. In June 1999, Pennsylvania's Governor signed into law the Natural Gas Choice and Competition Act (the Act) which requires local natural gas distribution companies to extend the availability of natural gas transportation service to residential and small commercial customers by July 1, 2000 pursuant to a plan approved by the Pennsylvania Public Utility Commission (PUC). In accordance with the Act, Equitable Gas made its restructuring filing on August 16, 1999. The filing was generally a restatement of Equitable's existing tariff, which reflected its earlier unbundling as previously described. The tariff provides for recovery of costs associated with Equitable Gas' existing pipeline capacity and natural gas supply contracts. The Company does not expect that the Act will have a material adverse impact on the financial statements. Equitable's distribution rates, terms of service, contracts with affiliates and issuance of securities are regulated primarily by the Pennsylvania PUC, along with the Kentucky Public Service Commission and the West Virginia Public Service Commission. Significant changes in the residential customer base are considered unlikely in the near term, even in the deregulated environment, due to the large investment in infrastructure required for residential natural gas transportation. On December 15, 1999, Equitable acquired the distribution, transmission and production operations of Carnegie Natural Gas. The Carnegie Natural Gas acquisition is complementary to Equitable's plans to grow its core business and increase utilization and operational efficiencies of its local distribution and interstate pipeline operations. The acquisition of Carnegie added approximately 8,000 new distribution customers. INTERSTATE PIPELINE Equitable Utilities' interstate pipeline operations include the natural gas transmission and storage activities of Equitrans, L.P. (Equitrans) and two smaller affiliates, Three Rivers Pipeline Corporation and Carnegie Interstate Pipeline Company, which are regulated by the Federal Energy Regulatory Commission (FERC). The pipeline division transported 73.6 billion cubic feet (Bcf) of natural gas to both affiliated and nonaffiliated customers in 1999. A substantial portion of the transportation system's annual throughput has been natural gas purchased by Equitable Gas. No margin loss is expected as a result of residential customers of Equitable Gas switching to other suppliers, as natural gas transported to Equitable Gas by such suppliers will continue to flow through this pipeline system. The evolving regulatory environment designed to increase competition in the natural gas industry has created a number of opportunities for pipeline companies to expand services and serve new markets. The Company has taken advantage of selected market expansion opportunities, concentrating on Equitrans' underground storage facilities and the location and nature of its pipeline system as a link between the country's major long-line natural gas pipelines. The pipeline operations consist of approximately 2,800 miles of transmission, storage and gathering lines, including 670 miles of transmission and gathering pipeline obtained in the December 1999 purchase of Carnegie Interstate Pipeline Company, and interconnections with five major interstate pipelines. Equitrans also has 15 natural gas storage reservoirs with approximately 500 MMcf per day of peak delivery capacity. The acquisition of the Carnegie assets enhances transportation access to large industrial customers in western Pennsylvania. ENERGY MARKETING Equitable Utilities' unregulated marketing operation purchases, stores and markets natural gas at both the retail and wholesale level, primarily in western Pennsylvania and West Virginia. Services and products offered by the marketing division include commodity procurement and delivery, physical natural gas management 4
5 operations and control, and customer support services to the Company's energy customers. To manage the price exposure risk of its marketing operations, the Company engages in risk management activities including the purchase and sale of financial energy derivative products. Because of this activity, this energy marketing division is also able to offer energy price risk management services to its larger industrial customers. EQUITABLE PRODUCTION Equitable Production explores for, produces and delivers natural gas and crude oil, with operations in the Appalachian and the Louisiana offshore Gulf of Mexico regions of the United States. It also engages in natural gas gathering and interstate transportation and the processing and sale of natural gas liquids. Equitable Production generated approximately 42 percent of the Company's net operating revenues in 1999. All of the information with respect to Equitable Production - East and Equitable Production - Gulf in this description of the business is current as of December 31, 1999. Subsequent to that date, the Company completed a substantial acquisition in Equitable Production - East and separately, agreed to merge the assets of Equitable Production - Gulf with those of another company. A description of these transactions is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations, Capital Resources and Liquidity, Acquisitions and Dispositions" and in Note V to the consolidated financial statements. EQUITABLE PRODUCTION - EAST Equitable Production - East is engaged in the development, production, acquisition, marketing, gathering and transportation of natural gas and oil in the Appalachian Basin. Equitable Production - East is one of the largest owners of proved natural gas reserves in the Appalachian Basin. The majority of the Company's exploration and production properties are located in the Appalachian Basin, which is the oldest and geographically one of the largest natural gas producing regions in the United States. Equitable Production - East currently owns approximately 6,400 net producing wells in Appalachia. As of December 31, 1999, the Company estimates the total proved reserves to be 1,067 billion cubic feet equivalent (Bcfe). Of this total, the Company estimates the proved developed reserves to be 907 Bcfe, with future net cash flows discounted at 10% before income taxes of approximately $652 million. Approximately 93% of the future net discounted cash flows before income taxes are represented by proved developed reserves located in eastern Kentucky and western Virginia and approximately 7% of the future net discounted cash flows before income taxes are represented by proved developed reserves located in Pennsylvania and West Virginia. As of December 31, 1999, the Company estimates proved undeveloped reserves to be 160 Bcfe. The areas in which the Company's Appalachian properties are located are characterized by wells with comparatively low rates of annual decline in production, low production costs and high Btu, or energy, content. Once drilled and completed, wells in the Appalachian Basin typically have low ongoing operating and maintenance requirements and minimal capital expenditures. These formations are characterized by slow recovery of the reserves in place, low rates of production and wells that generally produce for longer than 20 years and often more than 50 years. Many of the Company's wells in these areas have been producing for many years, 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 histories. Substantially all of the Appalachian wells are relatively shallow, with depths ranging from 1,000 to 7,000 feet below the surface. Many of these wells are completed in more than one producing zone and production from these zones may be mixed or commingled. Commingled production lowers producing costs on a per unit basis compared to isolated zone completions. Natural gas produced in the Appalachian Basin has historically received a premium over natural gas produced in other regions. The higher average prices are principally due to the proximity to a substantial number of industrial and commercial end-users in the northeast United States. For the period 1991 through 1998, natural gas price indices for Appalachian Basin production have averaged $0.25 per MMbtu more than prices for natural gas contracts traded on the NYMEX for the delivery of natural gas at Henry Hub, Louisiana. During these eight years, the average annual Appalachian Basin premium has ranged from $0.14 per MMbtu to $0.47 per MMbtu. 5
6 The Appalachian Basin premium is typically lower during warmer-than-normal winters, such as the previous two winters. The premium is somewhat offset by the high gathering and compression costs in the region. Natural gas sold from Equitable Production - East properties has historically received an additional premium because of its higher Btu content. The average Btu content for each cubic foot of natural gas produced from the Company's Appalachian properties is approximately 1,160, which has historically provided an average 16% premium over the standard measure of 1,000 Btu per cubic foot when calculating realized prices on a per Mcf basis. The productive lives of producing natural gas properties are often compared using their reserve-to-production index. This index is calculated by dividing total proved reserves of the property by annual production for the prior 12 months. The reserve-to-production index for the underlying properties at December 31, 1999 was approximately 23 years. This reserve-to-production index shows a relatively long producing life compared to an average index of 8.6 years for U.S. natural gas properties at year-end 1998. Because production rates naturally decline over time, the reserve-to-production index may not be a useful estimate of how long properties should economically produce. Based on the Company's reserve report, production from the underlying properties is expected to continue for at least 50 more years. Equitable Production - East has a record of successfully adding reserves to the underlying properties through development at costs which are generally less than U.S. industry averages. Over the three years ended December 31, 1999, Equitable Production - East has added through development drilling approximately 123 Bcfe of proved developed reserves at an average cost of $0.60 per Mcfe. For public reporting companies in the United States, the average industry cost of adding natural gas reserves from 1996 through 1998 was $0.76 per Mcfe. In addition, during 1998 and 1999, Equitable Production - East had substantial upward revisions of its proved undeveloped reserve estimates on the producing properties. Equitable Production - East currently has an inventory of 2.2 million gross acres, of which approximately 62% have not been developed. As of December 31, 1999, the Company estimated the proved undeveloped reserves of the underlying leases to be 160 Bcfe from 495 proved undeveloped drilling locations, with estimated future net discounted cash flows of $45 million. In the last three years, Equitable Production has completed approximately 99% of the wells it has drilled in Appalachia, adding 121 bcfe of proved natural gas and oil reserves. In December 1999, the unregulated production properties and operations of Equitable Utilities' Equitrans pipeline division were transferred to Equitable Production - East. These properties include 800 producing natural gas wells and 38.9 Bcfe of proved developed reserves. EQUITABLE PRODUCTION - GULF Equitable Production - Gulf conducts exploration and production activities in the U.S. Gulf of Mexico, primarily offshore the state of Louisiana. This is a very competitive market requiring substantial ongoing investment in federal leases, in which drilling and production activity by producers has increased in recent years. Approximately 12% of the Company's year-end natural gas and crude oil reserves are located in the Gulf region. Historically, Equitable Production has not been successful at consistently earning net income from its operations in the Gulf region. Equitable Production sold its oil and natural gas properties in six western states and the Canadian Rockies in the second half of 1997. The Company used a part of the proceeds from the property sales to finance the acquisition from Chevron USA of two producing natural gas and oil fields off Louisiana's Gulf Coast. ACQUISITION In December 1999, the Company completed the acquisition of Carnegie Natural Gas Company. The production operations of Carnegie include approximately 1,100 producing natural gas wells and 45.1 Bcfe of proved developed reserves. The Company estimates that the Carnegie acquisition will increase annual production of natural gas by approximately 8%. 6
7 COMPETITIVE ENVIRONMENT 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 1998, Kentucky and West Virginia had more than 500 independent operators and more than 85,000 producing oil and natural gas wells. Also, the historical availability of tax incentives has resulted in extensive drilling in the shallow formations with these low technical risk characteristics. HEDGING ACTIVITIES Equitable has historically entered into hedging contracts with respect to its natural gas and crude oil production at specified prices for a specified period of time. The Company's hedging strategy and information regarding derivative instruments used are outlined below in Item 7A, "Qualitative and Quantitative Disclosures About Market Risk." NATURAL GAS REGULATION The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation rates, storage tariffs and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. NORESCO NORESCO provides energy and energy related products and services that are designed to reduce its customers' operating costs and improve their productivity. NORESCO's customers include commercial, governmental, institutional and industrial end-users. The energy services business segment was formed in 1995 and was built through a series of acquisitions of privately held energy performance and facility management companies. NORESCO operates in a highly competitive industry, with a significant number of companies, including affiliates of large energy companies that have entered this market in recent years. NORESCO provided approximately 8 percent of the Company's net operating revenues in 1999. The majority of NORESCO's revenue and earnings comes from energy saving performance contracting services. NORESCO provides the following integrated energy management services: project development and engineering analysis; construction; management; financing; equipment operation and maintenance; and energy savings metering, monitoring and verification. The segment's energy infrastructure division develops and operates private power, cogeneration and central plant facilities in the U.S. and selected international markets. These projects serve a diverse clientele including hospitals, universities, 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. ERI Services is an autonomous business unit included for financial reporting purposes within the NORESCO segment. ERI Services provides energy savings performance contracting (ESPC) services exclusively to the federal government. In 1996, the Department of Defense (DOD) and the Department of Energy (DOE) initiated a series of competitive bids for ESPC contracts. The impetus for these programs are mandated targets to reduce energy use by 30% by the year 2005. These contracts serve as a "master" agreement between the DOD/DOE and an energy service company (ESCO), under which the ESCO may enter into individual site-specific contracts with government agencies to develop and implement ESPC projects. Under the terms of these agreements, the ESCO incurs the cost of developing and implementing projects in exchange for a defined share of the cost savings that result from the energy conservation measures, over the term of the contract. 7
8 At the end of 1999, NORESCO employed 338 people including professional staff, trades-people and plant operators. Construction backlog decreased from $86.8 million at year-end 1998 to $57.6 million at the end of 1999. The reduction in backlog is attributable mainly to the facilities management division, which completed the build-out of three large infrastructure projects during the fourth quarter of 1999. NORESCO completed $151.8 million of construction during 1999, an increase of $72.0 million over 1998. DISCONTINUED OPERATIONS In December 1998, the Company sold its natural gas midstream operations. The operations included an integrated gas gathering, processing and storage system in Louisiana and a natural gas and electricity trading and marketing business based in Houston, Texas, with an office in Calgary. These businesses are classified in the consolidated financial statements as discontinued operations. OPERATING REVENUES Operating revenues as a percentage of total operating revenues for each of the three business segments during the years 1997 through 1999 are as follows: <TABLE> <CAPTION> 1999 1998 1997 ---- ---- ---- <S> <C> <C> <C> Equitable Utilities: Residential natural gas sales............................. 19% 25% 32% Commercial and industrial natural gas sales............... 6 6 7 Marketed natural gas...................................... 31 28 27 Transportation service.................................... 8 6 5 Other..................................................... 1 2 2 --- --- --- Total Utilities........................................ 65 67 73 --- --- --- Equitable Production: Produced natural gas...................................... 14 15 11 Natural gas liquids....................................... 2 2 3 Crude oil................................................. 2 2 3 Other..................................................... 1 2 4 --- --- --- Total Production....................................... 19 21 21 --- --- --- NORESCO: Energy service contracting................................ 16 12 6 --- --- --- Total Revenues......................................... 100% 100% 100% === === === </TABLE> See Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes T and U to the consolidated financial statements in Part II, Items 7 and 8 for financial information by business segment and information regarding environmental matters. ITEM 2. PROPERTIES Principal facilities are owned by the Company's business segments with the exception of various office locations and warehouse buildings. A limited amount of equipment is also leased. The majority of transmission, storage and distribution pipelines 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. Equitable Gas and Carnegie Natural Gas own and operate natural gas distribution properties as well as other general property and equipment in Pennsylvania, West Virginia and Kentucky. Equitrans owns and operates production, underground storage and transmission facilities as well as other general 8
9 property and equipment in Pennsylvania and West Virginia. Three Rivers Pipeline Corporation and Carnegie Interstate Pipeline own transmission properties in southwestern Pennsylvania. Equitable Production. This business segment owns or controls all of the Company's acreage of proved developed and undeveloped natural gas and oil production properties principally located in the Appalachian region, with additional holdings in the U.S. Gulf of Mexico area. In addition, Kentucky West owns and operates gathering and transmission properties as well as other general property and equipment in Kentucky. Equitable Production's properties also include hydrocarbon extraction facilities in Kentucky with a 100-mile liquid products pipeline which extends into West Virginia. Information relating to Company estimates of natural gas and crude oil reserves and future net cash flows is provided in Note X to the consolidated financial statements in Part II. Natural Gas and Crude Oil Production: <TABLE> <CAPTION> 1999 1998 1997 ------- ------- ------- <S> <C> <C> <C> <C> Natural Gas -- MMcf produced............................... 66,328 62,135 58,952 -- Average sales price per Mcf sold............ $ 2.39 $ 2.41 $ 2.40 Crude Oil -- Thousands of barrels produced............... 1,070 996 1,544 -- Average sales price per barrel.............. $ 15.53 $ 13.59 $ 17.23 </TABLE> Average production cost (lifting cost) of natural gas and crude oil during 1999, 1998 and 1997 was $.373, $.462, and $.482 per Mcf equivalent, respectively. <TABLE> <CAPTION> NATURAL GAS OIL ----------- --- <S> <C> <C> <C> Total productive wells at December 31, 1999: Total gross productive wells.............................. 6,250 415 Total net productive wells................................ 6,087 370 Total acreage at December 31, 1999: Total gross productive acres.............................. 925,396 Total net productive acres................................ 880,520 Total gross undeveloped acres............................. 1,463,760 Total net undeveloped acres............................... 1,306,898 </TABLE> Number of net productive and dry exploratory and development wells drilled: <TABLE> <CAPTION> 1999 1998 1997 ----- ---- ---- <S> <C> <C> <C> Exploratory wells: Productive................................................ 3.5 4.3 2.9 Dry....................................................... 0.8 5.0 1.5 Development wells: Productive................................................ 118.6 74.6 88.7 Dry....................................................... -- 2.0 -- </TABLE> No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company's estimated total reserves. NORESCO. NORESCO is based in Framingham, Massachusetts, and leases offices in 24 locations throughout the country. Headquarters. The headquarters is located in leased office space in Pittsburgh, Pennsylvania. ITEM 3. LEGAL PROCEEDINGS Two subsidiaries of the Company, ET Blue Grass Company and EQT Capital Corporation, were among a group of defendants in a lawsuit filed by Raytheon Engineers & Constructors, Inc. (Raytheon). The lawsuit was filed in the Supreme Court of New York, Steuben County, in June 1997 for payment for work done by Raytheon in connection with a natural gas storage project in Avoca, New York. The storage project's operating partnership and partners, including another subsidiary of the Company, subsequently filed for bankruptcy. The claims of 9
10 Raytheon and other creditors against all defendants were settled by mediation. The Company's portion of the settlement is approximately $1 million, included in accrued liabilities at December 31, 1999. In May 1998, the jury in U.S. Gas Transportation, Inc. v. Equitable Resources Marketing Company, a breach of contract action filed in the Judicial District Court of Dallas County, Texas, in July 1996, returned a verdict against the Company in the amount of $4.36 million. On motion by the Company, the judge subsequently reduced the award to $762,000. Final judgment was entered, together with $550,000 in attorneys' fees. The case is on appeal. In Interstate Natural Gas Company v. Equitable Resources Energy Company et al. (including Kentucky West Virginia Gas Company), a royalty case filed in June 1995 in the Kentucky Circuit Court in Floyd County, the judge granted plaintiffs' motion for summary judgment against the Company for breach of fiduciary duty and contract unconscionability. In late 1998, the court entered judgment for damages totaling $1.9 million. After posting a guarantee of $2.6 million (including estimated postjudgment interest), the Company appealed the judgments to the Kentucky Court of Appeals. The Kentucky Court of Appeals has set oral argument for April 11, 2000. There are no other material pending legal proceedings, other than those which are adequately covered by insurance, to which the Company or any of its subsidiaries is a party, or to which any of their property is subject. 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, 1999. 10
11 EXECUTIVE OFFICERS OF THE REGISTRANT <TABLE> <CAPTION> NAME AND AGE TITLE BUSINESS EXPERIENCE - ------------ ----- ------------------- <S> <C> <C> Murry S. Gerber (47) President and First elected to present Chief Executive Officer position June 1, 1998; Chief Executive Officer of Coral Energy, Houston, TX, from November 1995; Treasurer, Shell Oil Company, Houston, from October 1994. Johanna G. O'Loughlin (53) Vice President, General Counsel Elected to present position May and Secretary 26, 1999; Vice President and General Counsel from December 19, 1996; Deputy General Counsel from April 1996; Senior Vice President and General Counsel of Fisher Scientific Company, Pittsburgh, PA, from June 1986. David L. Porges (42) Executive Vice President and Chief Elected to present position Financial Officer effective February 1, 2000; Senior Vice President and Chief Financial Officer from July 1, 1998; Managing Director, Bankers Trust Corporation, Houston, TX, and New York, NY, from December 1992. Gregory R. Spencer (51) Senior Vice President and Chief First elected to present Administrative Officer position May 23, 1996; Vice President-Human Resources and Administration from May 1995; Vice President-Human Resources from October 1994. Jeffrey C. Swoveland (44) Vice President - Finance First elected to present and Treasurer position May 23, 1996; Interim Chief Financial Officer from October 1997 to July 1998; Treasurer from December 1995; Director of Alternative Finance from September 1994. </TABLE> - --------------- Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified. Except as indicated, the officers listed above were elected on May 26, 1999. 11
12 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock is listed on the New York Stock Exchange and the Philadelphia Stock Exchange. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions as reported by The Wall Street Journal and the dividends declared and paid per share are summarized as follows (in U.S. dollars per share): <TABLE> <CAPTION> 1999 1998 --------------------------- --------------------------- HIGH LOW DIVIDEND HIGH LOW DIVIDEND ---- --- -------- ---- --- -------- <S> <C> <C> <C> <C> <C> <C> 1st Quarter.................................. 29 3/4 24 1/4 $0.295 35 1/4 29 5/8 $0.295 2nd Quarter.................................. 37 3/4 23 1/4 $0.295 35 27 $0.295* 3rd Quarter.................................. 39 35 15/16 $0.295 30 1/4 20 9/16 $0.295 4th Quarter.................................. 38 3/8 32 9/16 $0.295 29 15/16 25 $0.295 </TABLE> - --------------- * Actually declared near the end of the preceding quarter. As of February 29, 2000, there were approximately 5,400 shareholders of record of the Company's common stock. The indentures under which the Company's long-term debt is outstanding contain provisions limiting the Company's right to declare or pay dividends and make certain other distributions on, and to purchase any shares of, its common stock. Under the most restrictive of such provisions, $496 million of the Company's consolidated retained earnings at December 31, 1999 was available for declarations or payments of dividends on, or purchases of, its common stock. The Company anticipates dividends will continue to be paid on a regular quarterly basis. ITEM 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> 1999 1998 1997 1996 1995 ---------- ---------- ---------- ---------- ---------- (THOUSANDS EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> <C> Operating revenues............... $1,062,738 $ 870,628 $ 913,069 $ 856,367 $ 624,998 ========== ========== ========== ========== ========== Net income (loss) from continuing operations (a)................. $ 69,130 $ (27,052) $ 74,187 $ 53,527 $ 17,812 ========== ========== ========== ========== ========== Net income (loss) from continuing operations per common share: Basic....................... $ 2.03 $ (0.73) $ 2.06 $ 1.52 $ 0.51 ========== ========== ========== ========== ========== Assuming dilution........... $ 2.01 $ (0.73) $ 2.05 $ 1.52 $ 0.51 ========== ========== ========== ========== ========== Total assets..................... $1,789,574 $1,860,856 $2,328,051 $2,096,299 $1,963,313 Long-term debt................... $ 298,350 $ 281,350 $ 417,564 $ 422,112 $ 415,527 Preferred trust securities....... $ 125,000 $ 125,000 $ -- $ -- $ -- Cash dividends paid per share of common stock................... $ 1.18 $ 1.18 $ 1.18 $ 1.18 $ 1.18 </TABLE> - --------------- (a) Includes nonrecurring items in 1998 and 1997, as described in Management's Discussion and Analysis of Financial Condition and Results of Operations and in Notes C, D and F to the consolidated financial statements. Excludes discontinued operations and extraordinary items recognized in 1998 and 1997, as described in Management's Discussion and Analysis of Financial Condition and Results of Operations and in Notes E and L to the consolidated financial statements. 12
13 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CONSOLIDATED RESULTS OF OPERATIONS Equitable's consolidated net income from continuing operations for 1999 was $69.1 million, or $2.01 per diluted share, compared with a loss of $(27.1) million, or $(0.73) per diluted share, for 1998 and $74.2 million, or $2.05 per diluted share, for 1997. The improved 1999 earnings are due to increased natural gas production; increased throughput in the regulated distribution operations, primarily due to cooler weather; lower exploration costs; increased construction volume in the Company's NORESCO business; and lower operating and administrative expenses throughout the organization due to prior years' restructuring efforts coupled with continuing process improvement efforts in all significant business units. Equitable's net loss from continuing operations for 1998 of ($27.1) million, or ($0.73) per diluted share, compared with net income from continuing operations of $74.2 million, or $2.05 per diluted share, for 1997. In addition to the nonrecurring items described below, 1998 earnings were impacted by discontinued operations and an extraordinary loss on early extinguishment of debt, described in Notes E and L to the consolidated financial statements. In December 1998, the Company completed the sale of its natural gas midstream operations. Income (loss) from these discontinued operations after taxes was $(8.8) million or $(.24) per share in 1998; and $3.9 million, or $0.11 per share, for 1997. The 1998 results from discontinued operations are recorded net of an after-tax gain on the sale of the operations of $10.1 million, or $0.28 per share. In the fourth quarter of 1998, the Company recognized an extraordinary loss of $8.3 million after taxes, or $0.22 per share, for early retirement of certain long-term debt, repurchased with a portion of the proceeds of the sale of the midstream operations. Also, in 1998, the Company recognized $81.8 million for restructuring, impairment charges and nonrecurring items across all segments, and a $6.2 million reduction of utility operating revenues primarily as a result of the FERC rejection of a proposed pipeline rate case settlement in December 1998. Earnings for 1997 include the following items: an after-tax gain of $31.3 million, $0.87 per share, on the sale of certain crude oil and natural gas producing properties in the western United States and Canada and its contract drilling operations; an after-tax charge of $8.5 million, $0.24 per share, from the impairment of a proposed bedded salt natural gas storage project; and a $6.7 million after-tax charge, $0.19 per share, related to the evaluation and reduction of headquarters and noncore business functions. The decrease in operating income in 1998 compared to 1997, excluding restructuring, impairment charges and nonrecurring items, and the impact of the FERC settlement rejection, is primarily due to increased dry hole cost due to unsuccessful wells in the offshore region, decreases in crude oil and natural gas liquids prices, decreased sales volumes in the distribution division resulting from 19% warmer weather, and increased depreciation, depletion and amortization (DD&A) expense. The increase in DD&A is principally a result of increased production in the offshore Gulf of Mexico, where depletion rates are substantially higher than in the Company's other operating regions. The decrease in 1998 operating income was partially offset by higher revenues in the Equitable Utilities distribution division from increased customer charges in tariff rates established in the fourth quarter of 1997 and increased income from the inclusion of a full year of operations at NORESCO, acquired in mid-1997. BUSINESS SEGMENT RESULTS Business segment operating results are presented in the segment discussions and financial tables on the following pages. The Company revised its presentation of business segment information beginning with the 1999 Form 10-K. Equitable Energy is now reported in the Equitable Utilities segment instead of Equitable Services, and Equitable Services is now being reported as NORESCO. Prior periods have been reclassified to conform to the current presentation. 13
14 EQUITABLE UTILITIES Equitable Utilities' operations are comprised of the sale and transportation of natural gas to retail customers at state-regulated rates, interstate transportation and storage of natural gas subject to federal regulation, and the unregulated marketing of natural gas. DISTRIBUTION The local distribution operations of Equitable Gas Company (Equitable Gas) and Carnegie Natural Gas Company (Carnegie) provide natural gas services in southwestern Pennsylvania, municipalities in northern West Virginia and field line sales in eastern Kentucky. Equitable Gas and Carnegie are subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky. On April 1, 1998, Equitable Gas began to offer "unbundled" service to all of its customers in Pennsylvania, allowing them to choose their natural gas supplier. Revenues derived from transportation charges on natural gas sold by other suppliers enable Equitable Gas to minimize economic loss resulting from the switching of residential customers to other suppliers. Because the margin on natural gas bundled sales approximates the margin received on transportation-only volumes, Equitable Gas is economically neutral as to whether it provides transportation or sales to retail customers. In addition, the new rate structure approved by the Pennsylvania Public Utility Commission (PUC) increased the portion of revenues derived from the fixed monthly customer charge making margins for the residential distribution operation less sensitive to weather fluctuations. In June 1999, Pennsylvania Governor Ridge signed into law the Natural Gas Choice and Competition Act (the Act) which requires local natural gas distribution companies to extend the availability of natural gas transportation service to residential and small commercial customers by July 1, 2000 pursuant to a PUC-approved plan. In accordance with the Act, Equitable made its restructuring filing on August 16, 1999. The filing was generally a restatement of Equitable's existing tariff. The tariff provides for recovery of costs associated with Equitable Gas' existing pipeline capacity and natural gas supply contracts. The Company does not expect that the Act will have a material adverse impact on the financial statements. INTERSTATE PIPELINE The pipeline operations of Equitrans, L.P., Three Rivers Pipeline Corporation and Carnegie Interstate Pipeline are subject to rate regulation by the FERC. Under present rates, a majority of the annual costs are recovered through fixed charges to customers. Equitrans filed a rate case in April 1997, which addressed the recovery of certain stranded plant costs related to the implementation of FERC Order No. 636. The requested rates were placed into effect in August 1997, subject to refund, pending the issuance of a final order. On April 29, 1999, the FERC approved, without modification, the joint stipulated settlement agreement resolving all issues in the proceeding. The approved settlement provides for prospective collection of increased gathering charges. In addition, the settlement provides Equitrans the opportunity to retain all revenues associated with interruptible transportation and negotiated rate agreements, as well as moving its gathering charge toward a cost based rate. In the second quarter of 1999, Equitrans recorded the final settlement of the rate case, including adjustment of the prior provisions for refund and recognition of the previously deferred revenues and costs related to the stranding of certain gathering facilities. ENERGY MARKETING Equitable's unregulated marketing division provides natural gas operations, commodity procurement and delivery, risk management and customer services to energy consumers including large industrial, utility, commercial, institutional and residential end-users. This division'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. 14
15 CAPITAL EXPENDITURES Equitable Utilities has set the 2000 capital expenditure level at $32.0 million, a 26% increase over capital expenditures of $25.3 million for 1999. The 2000 capital expenditures include $24.4 million for the distribution operations and $7.6 million for pipeline operations, including maintenance and improvements to existing lines and facilities, and approximately $7.0 million for new business development opportunities. EQUITABLE UTILITIES <TABLE> <CAPTION> YEARS ENDED DECEMBER 31 -------------------------------- 1999 1998 1997 -------- -------- -------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Utility revenues........................................... $324,869 $322,057 $402,826 Marketing revenues......................................... 487,005 329,967 312,057 -------- -------- -------- Total revenues........................................ 811,874 652,024 714,883 Purchased natural gas cost................................. 573,101 449,098 492,678 Revenue related taxes...................................... 10,873 11,587 15,437 -------- -------- -------- Net revenues.......................................... 227,900 191,339 206,768 Operating and maintenance expense.......................... 67,923 68,749 71,137 Selling, general and administrative expense................ 43,740 55,153 63,346 Depreciation, depletion and amortization................... 35,596 20,570 19,778 Restructuring and impairment charges....................... -- 14,693 13,000 -------- -------- -------- Total expenses........................................ 147,259 159,165 167,262 -------- -------- -------- Operating income........................................... $ 80,641 $ 32,174 $ 39,507 ======== ======== ======== Capital expenditures....................................... $ 43,979 $ 20,860 $ 29,957 VALUE DRIVERS Operating expenses/net revenues............................ 64.62% 75.51% 80.89% Earnings (loss) before interest and taxes: Distribution............................................. $ 54,704 $ 30,385 $ 36,917 Pipeline................................................. 22,354 8,663 8,136 Marketing................................................ 3,583 (6,873) (5,547) </TABLE> Operating income for Equitable Utilities increased 150% from 1998 to 1999. Results for the 1999 period include $3.9 million from the recognition of the settlement of Equitrans' rate case described above. Results also include charges of $3.0 million for improvement of utility segment operating processes and consolidation of facilities. Results for 1998 include a pretax charge of $14.7 million related to restructuring as more fully described in Note C to the consolidated financial statements. Excluding the nonrecurring items in both periods, operating income increased $33.8 million, or 72.1% over the $46.9 million in 1998. The increase in 1999 is a result of higher net revenues due principally to cooler weather during the heating season, increased revenues from energy marketing activities and lower operating expenses due to restructuring initiatives begun in the fourth quarter of 1998. Operating income for Equitable Utilities decreased 18.5% from 1997 to 1998. Results for 1998 include charges related to restructuring of $14.7 million as described above. Results for 1997 include a charge of $13.0 million related to the Avoca natural gas storage project as more fully described in Note C to the consolidated financial statements. Excluding the nonrecurring items in both periods, operating income decreased $5.6 million to $46.9 million in 1998 due primarily to warmer weather and lower margins from marketed natural gas sales. 15
16 DISTRIBUTION OPERATIONS <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Net revenues............................................... $144,969 $133,393 $136,729 Operating costs............................................ 73,179 85,130 85,663 Depreciation, depletion and amortization................... 17,086 14,986 14,149 Restructuring and impairment charge........................ -- 2,892 -- -------- -------- -------- Operating income........................................... $ 54,704 $ 30,385 $ 36,917 ======== ======== ======== VALUE DRIVERS Degree days (normal = 5,964)............................... 5,485 4,808 5,919 O&M* per customer.......................................... $ 254.85 $ 311.94 $ 309.61 Volumes (MMcf): Residential.............................................. 25,431 22,641 28,503 Commercial industrial.................................... 22,209 19,165 21,383 -------- -------- -------- Total natural gas sales and transportation............ 47,640 41,806 49,886 ======== ======== ======== </TABLE> - --------------- * O&M is defined for this calculation as the sum of operating and maintenance and selling, general and administrative expenses, excluding other taxes. Weather in the distribution service territory during 1999 was 8% warmer than normal (normal is based on the 30-year average determined by the National Oceanic and Atmospheric Administration) but 14% cooler than 1998. Total system throughput increased 5.8 billion cubic feet (Bcf) primarily as a result of the cooler weather's effect on residential and commercial customers who use natural gas for heating. Net revenues for the distribution operations increased 8.7% from 1998 to 1999. The increase in net revenues for 1999 is due to the impact of weather that was 14% colder than the prior year. In addition, total margin from delivery service customers was higher in 1999, reflecting higher average delivery service rates and slightly higher volumes transported. Operating expenses for the distribution operations for 1999 decreased 12.4% from 1998. Results for 1998 period include $2.9 million related to the restructuring of utility segment operating functions and consolidation of facilities. Excluding the restructuring charge in 1998, operating expenses decreased $9.9 million, or 9.8%, over the $100.1 million in 1998. The decrease in 1999 is due principally to restructuring initiatives begun in the fourth quarter of 1998. Operating income for 1999 increased 64.4% from the operating income of 1998, excluding the impact of restructuring charges. The increase was due primarily to higher throughput, resulting from the colder weather and lower operating expenses due to restructuring initiatives begun in the fourth quarter of 1998. Net revenues for the distribution operations decreased 2.4% from 1997 to 1998. The decrease in net revenues for 1998 is due to the impact of weather that was 19% warmer than the prior year. This decrease was partially offset by an increase in net revenues from fixed monthly customer charges of $12.5 million, which reduced the earnings impact of the lower throughput. Operating expenses of $100.1 million for 1998, excluding restructuring charges of $2.9 million, were substantially unchanged from the $99.8 million for 1997. Operating income of $33.3 million for 1998, excluding the impact of restructuring charges, decreased $3.6 million, or 9.9%, from the operating income of $36.9 million for 1997. The decrease was due primarily to lower throughput resulting from the warmer weather, partially offset by the impact of the new rate structure. 16
17 PIPELINE OPERATIONS <TABLE> <CAPTION> 1999 1998 1997 ------- ------- ------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Net revenues................................................ $73,273 $51,344 $60,575 Operating costs............................................. 32,607 28,611 34,433 Depreciation, depletion and amortization.................... 18,312 5,299 5,006 Restructuring and impairment charge......................... -- 8,771 13,000 ------- ------- ------- Operating income............................................ $22,354 $ 8,663 $ 8,136 ======= ======= ======= VALUE DRIVERS Transportation throughput (MMBtu)........................... 76,727 67,590 75,016 </TABLE> Net revenues for the pipeline operations increased 42.7% from 1998 to 1999. Pipeline revenues in 1999 include $15.5 million related to recognition of the rate settlement and pass-through of stranded costs described above and $1.7 million for the pass-through of FERC surcharges and products extraction costs to customers. Net revenues of $56.1 million for the period, excluding the impact of the rate settlement and extraction revenues, increased $4.8 million, or 9.4%, over the $51.3 million for the 1998 period. The increase in revenues for 1999 was due primarily to increased margins on gathering throughput and increased storage service revenues. Operating expenses increased 19.3% in 1999 over 1998. The operating expenses for 1999 include $11.6 million of amortization expense related to the stranded plant from recognition of the rate settlement, $1.7 million of products extraction costs and $4.0 million for utility segment process improvements as more fully described above. Operating expenses for 1998 include restructuring charges of $8.8 million as more fully described in Note C to the consolidated financial statements. Operating expenses, excluding the nonrecurring charges in both periods, were substantially the same. Excluding the nonrecurring items in both periods, operating expenses of $33.6 million reflected a decrease of $0.3 million from $33.9 million in 1998. Excluding the impact of nonrecurring charges in both periods, operating income of $22.4 million for 1999 increased $4.9 million, or 28.2%, from the operating income of $17.4 million for 1998. The increase in operating income is due primarily to increased revenues from the pipeline gathering and storage services and the benefit of restructuring initiatives. Net revenues for the pipeline operations decreased 15.2% in 1998 from 1997. The decrease in revenues for 1998 was due primarily to lower unit margin rates and reduced revenues from extraction services resulting from a change in the contract arrangements. Operating expenses decreased 18.6% from 1997 to 1998. The operating expenses for 1998 and 1997 include nonrecurring charges of $8.8 million and $13.0 million, respectively, as more fully described above. The decrease in expenses for 1998, excluding nonrecurring charges, was due primarily to lower expenses for extraction services resulting from a change in the contract arrangements, lower benefits costs reflecting regulatory treatment and lower corporate overhead costs. Excluding the impact of nonrecurring charges in both periods, operating income of $17.4 million for 1998 decreased $3.7 million, or 17.5%, from the operating income of $21.1 million for 1997. The decrease in operating income is due primarily to lower margins due to the 1997 base rate case partially offset by reduced operating costs. 17
18 ENERGY MARKETING <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Net revenues............................................... $ 9,658 $ 6,603 $ 9,464 Operating costs............................................ 5,877 10,161 14,387 Depreciation, depletion and amortization................... 198 285 624 Restructuring and impairment charge........................ -- 3,030 -- -------- -------- -------- Operating income (loss).................................... $ 3,583 $ (6,873) $ (5,547) ======== ======== ======== VALUE DRIVERS Marketed gas sales (MMBtu)................................. 181,453 134,455 111,031 Net revenue/MBtu........................................... $ 0.0513 $ 0.0471 $ 0.0740 </TABLE> The increase in gross margins in 1999 is attributable to increased throughput and more extensive use of storage. The increased volume in 1999 compared to 1998 is a result of the addition of residential customer choice programs in Pennsylvania and Ohio and increased utility/marketing company volumes transported during the 1999 winter heating season. Gross margin per MMBtu was also higher in 1999, due primarily to the residential choice programs and greater volatility in weather in 1999. The 1999 decrease in operating costs is primarily due to a significant staff reduction and office closings completed as part of the corporate-wide restructuring in the fourth quarter of 1998. Net revenues decreased by $2.9 million in 1998 from 1997. A large group of high margin customers were renewed at lower rates reflecting the highly competitive nature of the business. Also in the last half of 1998, the business yielded lower margins due to decreased throughput for large industrial steel producing clients. SG&A expenses decreased from 1997 to 1998 by $4.2 million. The decreases were due primarily to decreased consulting costs and reduced staffing and office closures. Included in 1998 operating costs is a $3.0 million restructuring charge for office closings and personnel reductions. EQUITABLE PRODUCTION Production operations comprise the production and sale of natural gas, natural gas liquids and crude oil through Equitable Production Company (Equitable Production). In 1999, the exploration and production operations conducted by Equitrans were transferred to Equitable Production - East from Equitable Utilities. The financial results of both segments have been restated to reflect the new structure for all periods presented. EQUITABLE PRODUCTION - EAST In the Appalachian Region during 1999, 153 gross wells were drilled at a success rate of 100%. This drilling was concentrated within the core areas of southwest Virginia and southeast Kentucky. This activity resulted in an additional 9 Mcf per day of gas sales and proved reserve additions of 46.5 Bcfe. EQUITABLE PRODUCTION - GULF In the Gulf Region during 1999, 11 gross wells were drilled at a success rate of 82%. This activity resulted in additions of 48.5 Bcfe. The increase is the result of successful development of the West Cameron Block 180 and 198 fields and South Marsh Island 39 field. Equitable Production operates both fields. Equitable Production also participated in exploratory activity during the year, including a successful well at South Timbalier 196, in which Equitable Production has a 50% working interest. Unsuccessful exploratory activity during 1999 on the West Cameron 575 and the Eugene Island 44 blocks resulted in dry hole expense of approximately $2.5 million in 1999. 18
19 CAPITAL EXPENDITURES Equitable Production has set the 2000 capital expenditure level at $116 million. This includes $46 million for exploration and development drilling in the Gulf of Mexico and $70 million for development of Appalachian holdings, including $4 million for improvements to gathering system pipelines. The evaluation of new prospects, market forecasts and price trends for natural gas and oil will continue to be the principal factors for the economic justification of drilling investments. EQUITABLE PRODUCTION <TABLE> <CAPTION> YEARS ENDED DECEMBER 31 -------------------------------- 1999 1998 1997 -------- -------- -------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Operating revenues......................................... $211,821 $200,479 $251,396 Cost of energy purchased................................... 24,188 21,494 26,543 -------- -------- -------- Net operating revenues................................ 187,633 178,985 224,853 Operating expenses: Operation and maintenance................................ 12,956 13,991 31,579 Lease operating expense.................................. 26,206 30,289 31,851 Dry hole................................................. 2,455 23,101 2,738 Other exploration........................................ 6,833 4,110 4,523 Selling, general and administrative...................... 26,003 30,783 30,922 Depreciation, depletion and amortization................. 58,565 56,380 50,418 Restructuring charges.................................... -- 44,675 2,200 -------- -------- -------- Total operating expenses.............................. 133,018 203,329 154,231 -------- -------- -------- Operating income (loss).................................... $ 54,615 $(24,344) $ 70,622 ======== ======== ======== Capital expenditures....................................... $ 92,099 $126,752 $185,558 VALUE DRIVERS Natural gas sales (MMcf)................................... 63,863 59,551 56,847 Crude oil sales (MBbls).................................... 1,070 996 1,544 Natural gas liquids sales (MGals.)......................... 66,072 67,137 65,525 Produced natural gas and oil (MMcfe)....................... 72,745 68,110 68,215 Average selling prices: Natural gas (per Mcf).................................... $ 2.39 $ 2.41 $ 2.40 Crude oil (per barrel)................................... $ 15.53 $ 13.59 $ 17.23 Natural gas liquids (per gallon)......................... $ 0.30 $ 0.27 $ 0.38 </TABLE> Net operating revenues, which are derived primarily from the sale of produced natural gas, crude oil and natural gas liquids, increased 4.8% from 1998 to 1999. The increase in net operating revenues of $8.6 million in 1999 compared to 1998, is due primarily to increases in natural gas sales volumes ($7.8 million), crude oil sales prices ($3.1 million), and natural gas liquids sales prices ($2.1 million). These improvements were offset somewhat by a $1.3 million reduction in transportation revenues due to lower throughput. In addition, 1998 includes $2.6 million of direct bill revenues resulting from a FERC pricing settlement, as described in Note D to the consolidated financial statements. Operating expenses decreased 34.6% in 1999 from 1998. The 1998 expenses include nonrecurring items primarily associated with write-downs of the carrying value of assets of approximately $44.7 million. The 1998 operating expenses also include $23.1 million of dry hole expense associated with the unsuccessful drilling of five exploratory prospects offshore in the Gulf of Mexico compared to $2.5 million in 1999 associated with two exploratory prospects. Other exploration expenses increased $2.7 million in 1999 due primarily to a lease impairment and the impairment of an equity investment in an oil and natural gas production company. Depreciation, depletion and amortization (DD&A) increased $2.2 million in 1999 because of increased 19
20 production and a $1.0 million impairment associated with the abandonment of a processing facility. Also included in 1999 operating expenses is $2.8 million related to process improvements, including the Company's decision to close its regional office in Kingsport, Tennessee, consolidate administration and realign field offices; $2.0 million of charges related to the decertification of Kentucky West Virginia Gas Company; and $1.8 million in performance-related compensation. Partially offsetting these items are $700,000 and $1.0 million reductions in environmental and pension liabilities, respectively. The decrease in operating expenses in 1999 of approximately $14.6 million, excluding the items above, is due to continued improvements in operating efficiencies and decreased staff, as a result of the initiatives begun in 1998. Net operating revenues decreased 20.4% from 1997 to 1998. Included in 1997 are $5.2 million additional revenues from direct bill settlements as described in Note D to the consolidated financial statements, $18.3 million from contract drilling services associated with Union Drilling, a contract drilling operation which the Company sold in 1997, and $22.8 million from the western United States and Canada oil and natural gas properties sold in 1997. The decrease in net operating revenues of $0.5 million in 1998 compared to 1997, excluding nonrecurring amounts and sold operations, is due primarily to decreases in commodity prices and reduced transportation revenues from affiliated companies. These decreases are essentially offset by increased natural gas and crude oil production excluding production associated with the operations in the western United States and Canada. Operating expenses for 1998 increased 32% from 1997. The 1998 operating expenses include the restructuring charges of $44.7 million discussed above. The 1998 operating expenses also include approximately $23.1 million of dry hole expense primarily associated with unsuccessful drilling of five exploratory prospects offshore Gulf of Mexico. Included in the 1997 amounts is approximately $34.4 million of operating expenses associated with the assets sold in 1997. The increase in operating expenses in 1998, excluding the nonrecurring items and sold operations, is primarily due to higher DD&A from increased production. Additionally, production expenses increased $4.5 million in the Gulf operations as a result of a full year of the 1997 acquisition of West Cameron 180 and 198 fields. PRODUCTION - EAST OPERATIONS <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Net operating revenues..................................... $122,739 $126,450 $154,517 Operating costs............................................ 53,064 55,940 56,689 Depreciation, depletion and amortization................... 29,141 28,728 28,905 Restructuring charges...................................... -- 7,575 -- -------- -------- -------- Operating income........................................... $ 40,534 $ 34,207 $ 68,923 ======== ======== ======== VALUE DRIVERS Natural gas sales (MMcf)................................... 40,763 40,649 40,940 Crude oil sales (MBbls).................................... 445 502 531 Natural gas liquids sales (MGals).......................... 59,062 61,878 61,900 Average selling prices: Natural gas (per Mcf).................................... $ 2.46 $ 2.47 $ 2.60 Crude oil (per barrel)................................... $ 14.33 $ 11.22 $ 17.12 Natural gas liquids (per gallon)......................... $ 0.30 $ 0.27 $ 0.38 LOE/Mcfe sales............................................. $ 0.445 $ 0.463 $ 0.450 G&A/Mcfe sales............................................. $ 0.438 $ 0.473 $ 0.467 Depletion/Mcfe produced.................................... $ 0.418 $ 0.445 $ 0.447 </TABLE> Net operating revenues for the East operations decreased 3% from 1998 to 1999. The decrease in net operating revenues of $3.7 million in 1999 compared to 1998 is primarily attributable to a $1.3 million reduction in transportation revenues in 1999 due to lower throughput and the direct bill settlements recognized in 1998 of 20
21 $2.6 million. These unfavorable variances are partially offset by the positive effects of higher crude oil and natural gas liquids prices. Operating expenses decreased 11% in 1999 from 1998. The decrease in operating expenses of $10 million in 1999 is due primarily to the $7.6 million of nonrecurring items in 1998 primarily associated with write-downs of the carrying value of assets. The remaining positive variance is due to continued improvements in operating efficiencies and decreased staff partially offset by charges for 1999 process improvements discussed in the Equitable Production comparison above. Net operating revenues decreased 18% from 1997 to 1998 primarily due to lower commodity prices and reduced transportation revenues from affiliated companies. In addition, 1997 includes $5.2 million of additional revenues from direct bill settlements. Operating expenses for 1998 were $6.6 million higher than 1997 due to the $7.6 million of restructuring charges recorded in 1998. PRODUCTION - GULF OPERATION <TABLE> <CAPTION> 1999 1998 1997 ------- -------- ------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Net operating revenues...................................... $64,894 $ 52,535 70,336 Operating costs............................................. 21,389 46,334 44,925 Depreciation, depletion and amortization.................... 29,424 27,652 21,512 Restructuring charges....................................... -- 37,100 2,200 ------- -------- ------- Operating income (loss)..................................... $14,081 $(58,551) $ 1,699 ======= ======== ======= VALUE DRIVERS Natural gas sales (MMcf).................................... 23,100 18,902 15,907 Crude oil sales (MBbls)..................................... 625 494 1,013 Natural gas liquids sales (MGals)........................... 7,010 5,259 3,625 Average selling prices: Natural gas (per Mcf)..................................... $ 2.26 $ 2.28 $ 1.88 Crude oil (per barrel).................................... $ 16.38 $ 15.99 $ 17.30 Natural gas liquids (per gallon).......................... $ 0.26 $ 0.16 $ 0.36 LOE/Mcfe sales.............................................. $ 0.256 $ 0.461 $ 0.544 G&A/Mcfe sales.............................................. $ 0.260 $ 0.463 $ 0.469 Depletion/Mcfe produced..................................... $ 1.090 $ 1.216 $ 0.849 </TABLE> Net operating revenues for the Gulf operations increased 24% from 1998 to 1999. The increase in net operating revenues of $12.4 million in 1999 compared to 1998, is due primarily to increases in natural gas and crude oil sales volumes of $8.0 million and $2.1 million, respectively. In addition, higher commodity prices in 1999 contributed $1.8 million to the increase in net operating revenues. Operating expenses decreased 54.3% in 1999 from 1998. The 1998 expenses include $37.1 million of restructuring charges and $23.1 million of dry hole expense associated with the unsuccessful drilling of five wells. In 1999, two unsuccessful exploratory wells were drilled for a total of $2.5 million of dry hole cost. Other exploration expenses increased $2.0 million in 1999 due primarily to a lease impairment and the impairment of an equity investment in an oil and natural gas production company. DD&A increased $1.8 million in 1999 because of increased production. The remaining positive variance of $6.2 million is due to continued improvements in operating efficiencies and decreased staff. Net operating revenues decreased 25.3% from 1997 to 1998. Revenues in 1997 include $41.1 million associated with Union Drilling and the western United States and Canada operations, which were all sold during 1997. The increase in operating revenues of $23.3 million in 1998 compared to 1997, excluding sold operations, 21
22 is due primarily to increased production of natural gas and crude oil from the acquisition of West Cameron 180 and 198 in the fourth quarter 1997. Operating expenses for 1998 increased 61.8% from 1997. Excluding the 1998 restructuring charges and dry hole expenses, which are discussed above, and $34.4 million of 1997 operating costs related to the assets sold in that year, total operating expenses increased $16.7 million in 1998 compared with 1997. This increase is due primarily to higher depreciation and depletion from increased production. Additionally, production expenses increased $4.5 million as a result of a full year of the 1997 acquisition of the West Cameron 180 and 198 fields. NORESCO NORESCO provides energy and energy related products and services that are designed to reduce its customers' operating costs and improve their productivity. NORESCO's customers include commercial, governmental, institutional and industrial end-users. The majority of NORESCO's revenue and earnings comes from energy saving performance contracting services. NORESCO provides the following integrated energy management services: project development and engineering analysis; construction; management; financing; equipment operation and maintenance; and energy savings metering, monitoring and verification. NORESCO also manages the segment's facilities management division, which develops and operates private power, cogeneration and central plant facilities in the U.S. and selected international markets. <TABLE> <CAPTION> 1999 1998 1997 -------- -------- ------- (THOUSANDS) <S> <C> <C> <C> FINANCIAL DATA Energy service contracting revenues......................... $169,633 $109,493 $52,790 Energy service contract cost................................ 133,088 80,800 37,164 -------- -------- ------- Gross margin........................................... 36,545 28,693 15,626 -------- -------- ------- Operating expenses: Selling, general and administrative....................... 19,889 19,218 15,298 Depreciation, depletion and amortization.................. 6,078 4,300 2,775 Restructuring charges..................................... -- 2,716 200 -------- -------- ------- Total operating expenses............................... 25,967 26,234 18,273 -------- -------- ------- Operating income (loss)..................................... 10,578 2,459 (2,647) Other income................................................ 2,863 2,667 -- -------- -------- ------- Earnings (loss) before interest and taxes................... $ 13,441 $ 5,126 $(2,647) ======== ======== ======= Capital expenditures........................................ $ 6,041 $ 11,102 $28,096 VALUE DRIVERS Contract backlog at December 31 (thousands)................. $ 57,299 $ 77,270 $15,296 Gross profit margin......................................... 21.5% 26.2% 29.7% SG&A as a % of revenue...................................... 11.7% 17.6% 29.0% Development expense as a % of revenue....................... 2.6% 3.3% 2.6% </TABLE> Revenues increased from 1998 to 1999 by $60.1 million, or 55%, reflecting the continued expansion of the business. Total construction completed during 1999 was $151.8 million, an increase of $72.0 million over 1998. Gross margins from energy services contracting activities decreased to 21.5% in 1999 from 26.2% in 1998. The deterioration in gross margin results mainly from the higher proportion of lower margin government contracts implemented in 1999. SG&A expenses increased from 1998 to 1999 by $0.7 million. Increases during 1999 include project development expense of $0.8 million, marketing expense of $0.2 million and rent expense of $0.1 million which were partially offset by a $0.7 million reduction in corporate overhead expense. 22
23 Depreciation, depletion and amortization (DD&A) expense increased from 1998 to 1999 by $1.8 million, or 41.3%. This increase is primarily due to the company's cogeneration facility in Jamaica which was put into service in February 1999. Other income of $2.9 million in 1999 and $2.7 million in 1998 reflects NORESCO's share of the earnings from its equity investments in power plant assets, primarily a 50 mega-watt facility in Panama which is 50% owned by the company. A 96 mega-watt facility in Panama and a 7 mega-watt facility in Providence, RI were brought on line in late 1999. Revenues increased from 1997 to 1998 by $56.7 million. On an annualized basis, NORESCO's revenues increased by 74% from 1997 to 1998 reflecting both the continued expansion of the business and a movement toward higher value contracts. Total construction completed during 1998 was $79.7 million, an increase of $49.0 million over 1997. Gross margins from energy services contracting activities decreased to 26.2% in 1998 from 29.7% in 1997. The deterioration in gross margin is a result of a change in the mix of contracts due to the increase in revenues from the lower margin government market and increased competition. SG&A expenses increased from 1997 to 1998 by $3.9 million. Increases in corporate overhead expense of $2.0 million and NORESCO's SG&A of $6.0 million (12 months in 1998 compared to 7 months in 1997) were partially offset by expense reductions in NORESCO's facilities management division of $2.1 million. ERI Services reduced SG&A expense by $3.2 million in 1998, reflecting a shift away from a start-up enterprise focused mainly on business and staff development and toward a focus on implementation and construction of contract assets. DD&A expense increased from 1997 to 1998 by $1.5 million. This increase reflects goodwill amortization for the full year in 1998 of $3.7 million as compared to $2.2 million in 1997. 1998 AND 1997 RESTRUCTURING, IMPAIRMENT AND OTHER NONRECURRING CHARGES During 1998, management expressed its intention to focus on fundamental strengths in its core businesses. In October 1998, the Company's Board of Directors approved a restructuring plan. As a result of this plan, along with its earlier decision to discontinue and sell the natural gas midstream business, and the sustained decrease in oil and natural gas commodity prices, the Company took specific actions to reduce its overall cost structure. Certain of the actions taken by the Company resulted in pretax impairment, restructuring and other nonrecurring charges in the fourth quarter of 1998 amounting to $81.8 million. The restructuring activities (shown below in tabular format) primarily relate to the following: The elimination of employment positions Company-wide: Early in the fourth quarter of 1998, the Company announced that the restructuring plan would eliminate a substantial number of positions. Related charges included severance packages, cash payments made directly to terminated employees as well as outplacement services and noncash charges for curtailment of certain defined benefit pension and other postretirement benefit plans. A total of 164 employees terminated employment. Redirection of offshore Gulf production: As a result of the decrease in oil and natural gas prices and unsuccessful drilling results in several of the Company's nonoperated blocks, a review of the Gulf operations was undertaken. The Company eliminated several layers of management and focused its operations on lower risk, Company-operated exploration and development. In addition, the production and commodity price trends indicated that the undiscounted cash flows from this division would be substantially less than the carrying value of the producing properties. Producing property write-downs were measured based on a comparison of the assets' net book value to the net present value of the properties' estimated future net cash flows. The undeveloped leases no longer intended to be developed were written down to estimated market value less costs to dispose. Improved integration of Appalachian production operations: To improve the efficiency of Appalachian production operations, the Company obtained authority in 1999 from the Federal Energy Regulatory Commission to decertify the pipeline facilities of Kentucky West Virginia Gas Company, LLC. 23
24 Decentralization of administrative functions: In the fall of 1998, management initiated a major decentralization and downsizing of administrative functions. Costs incurred, in addition to severance and other employee separation costs described above, included one-time costs for third party processing, costs to make assets available for sale, lease cancellations for office and computer equipment and noncash charges for the write-down of assets no longer in use and subsequently sold. Exiting certain noncore businesses: As a result of the continued evaluation of profitability of the Company's nonregulated retail natural gas sales business, the Company has refocused its marketing along core regional lines and eliminated five field offices. In addition, the Company intends to curtail its involvement in several auxiliary business ventures, such as radio dispatch operations and residential real estate development, and has written these investments down to net realizable value. <TABLE> <CAPTION> RESERVE RESERVE CASH/ RESTRUCTURING 1998 BALANCE AT 1999 BALANCE AT NONCASH CHARGE ACTIVITY 12/31/98 ACTIVITY 12/31/99 ------- ------------- -------- ---------- -------- ---------- 1998 (MILLIONS) <S> <C> <C> <C> <C> <C> <C> Elimination of employment positions Company-wide: Severance and other employment packages........................... Cash $ (8.2) $ 2.6 $(5.6) $5.6 $-- Pension/other benefit plan curtailments....................... Noncash (2.1) 2.1 -- -- -- Other................................ Cash (0.8) 0.5 (0.3) 0.3 -- Redirection of offshore Gulf production: Impairment of undeveloped leases..... Noncash (15.9) 15.9 -- -- -- Impairment of producing properties... Noncash (19.6) 19.6 -- -- -- Improved integration of Appalachian production operations: Impairment of regulatory assets...... Noncash (4.0) 4.0 -- -- -- Impairment of undeveloped leases..... Noncash (1.4) 1.4 -- -- -- Decentralization of administrative functions: Impairment of headquarters building........................... Noncash (5.1) 5.1 -- -- -- Impairment of enterprise-wide computer system.................... Noncash (7.7) 7.7 -- -- -- Impairment of other assets........... Noncash (3.3) 3.3 -- -- -- Exiting certain noncore businesses: Office closing/lease buyout.......... Cash (1.7) 1.6 (0.1) 0.1 -- Impairment of radio system assets/buyout lease................ Noncash/Cash (3.3) 2.1 (1.2) 1.2 -- Impairment of investments............ Noncash (1.5) 1.5 -- -- -- Impairment of other assets........... Noncash (3.6) 3.6 -- -- -- Impairment of pipeline stranded costs.............................. Noncash (3.6) 3.6 -- -- -- ------ ----- ----- ---- --- Total.................................... $(81.8) $74.6 $(7.2) $7.2 $-- ====== ===== ===== ==== === </TABLE> 24
25 In 1997, the Company recognized an impairment charge of $13.0 million related to its investment in a proposed bedded-salt natural gas storage project and began the restructuring of its headquarters and nonregulated energy sales offices. These latter actions resulted in an operating charge in that quarter of $11.1 million. The 1997 restructuring activities primarily relate to the following: <TABLE> <CAPTION> RESERVE RESERVE CASH/ RESTRUCTURING 1997 BALANCE AT 1998 BALANCE AT NONCASH CHARGE ACTIVITY 12/31/97 ACTIVITY 12/31/98 ------- ------------- -------- ---------- -------- ---------- 1997 (MILLIONS) <S> <C> <C> <C> <C> <C> <C> Downsize headquarters staff: Severance packages.............. Cash $ (3.1) $ 2.8 $(0.3) $0.3 $-- Terminate consulting contracts..................... Cash (2.1) 2.1 -- -- -- Impairment of assets............ Noncash (1.7) 1.7 -- -- -- Impairment of investments....... Noncash (2.2) 2.2 -- -- -- Airplane lease exit costs....... Cash (1.7) 1.7 -- -- -- Other........................... Cash (0.3) 0.3 -- -- -- Exit Avoca storage project: Impairment of investment........ Noncash (12.7) 12.7 -- -- -- Other........................... Cash (0.3) 0.3 -- -- -- ------ ----- ----- ---- --- Total......................... $(24.1) $23.8 $(0.3) $0.3 $-- ====== ===== ===== ==== === </TABLE> OTHER INCOME STATEMENT ITEMS OTHER INCOME <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, ----------------------------- 1999 1998 1997 ------ ------ ------- <S> <C> <C> <C> Other income (thousands): Gain on sale of assets.................................... $ -- $ -- $50,120 Equity earnings of nonconsolidated subsidiaries........... 2,863 2,667 -- ------ ------ ------- Total other income..................................... $2,863 $2,667 $50,120 ====== ====== ======= </TABLE> In 1997, Equitable Production entered into sales agreements for $170 million with five purchasers covering its crude oil and natural gas properties in the western United States and Canada. Also in 1997, Equitable Production sold its Union Drilling division, a contract drilling company. These asset sales in 1997 resulted in pretax gains of $50.1 million. There were no other significant changes in other income between 1999 and 1997. INTEREST CHARGES <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, ------------------------------- 1999 1998 1997 ------- ------- ------- <S> <C> <C> <C> Interest charges (thousands)................................ $37,132 $40,302 $34,903 ======= ======= ======= </TABLE> Interest costs decreased in 1999 as a result of an $86 million decrease in average debt outstanding, due to proceeds from the sale in late 1998 of the natural gas midstream operations, lower capital expenditures and improved cash flows from operations. The savings from the lower debt level were partially offset by a slightly higher overall interest rate, due to the full year effect of the Preferred Trust Debentures issued in 1998. Interest costs increased in 1998 as a result of a $44 million increase in average debt outstanding during the year and an increase in the Company's average overall interest rate. The increase in debt outstanding was due to increased capital spending for Gulf of Mexico and midstream projects completed during 1998. The increased rate is due to the April 1998 issuance of 7.35% Preferred Trust Debentures, which replaced lower rate commercial paper borrowings. Interest charges for 1998 and 1997 exclude interest related to discontinued operations sold in 1998. Average annual interest rates on short-term debt remained relatively constant, in a range of 5.0% to 5.7%, throughout the three-year period. 25
26 CAPITAL RESOURCES AND LIQUIDITY WORKING CAPITAL During 1998, the Company divested its natural gas midstream operations. Prior to this divestiture, these operations had entered into large volume natural gas trading contracts with expiration dates in 1999. Subsequent to the divestiture, these contracts were served out by the Energy Marketing division of Equitable Utilities. The balance in accounts receivable and payable at December 31, 1998 included $42.4 million and $44.8 million, respectively, related to these deals, which did not recur in 1999. There were no other significant changes in working capital between 1998 and 1999. HEDGING The Company's overall objective in its hedging program is to protect earnings from undue exposure to the risk of falling commodity prices. Since it is primarily a natural gas company, this leads to different approaches to hedging natural gas than for crude oil and natural gas liquids. 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 year 2000. Its preference is to use derivative instruments that create a price floor, in order to provide down-side protection while allowing the Company to participate in a portion of the upward price movements. This is accomplished with the use of a mix of costless collars, straight floors and some fixed price swaps. This mix allows the Company to participate in a range of prices, while protecting shareholders from significant price deterioration. In addition to this current strategy, part of the Company's portfolio of natural gas hedges is a swap entered into in 1995 as part of a financing transaction. This swap, covering about 15% of natural gas production at a NYMEX price of $1.82/Mcf, expires near the end of the year 2000. Crude oil and natural gas liquids prices are currently at relatively high levels compared to historical averages. As a result, the Company has used swaps and other derivative instruments to lock in current prices for the majority of expected production of crude oil and of natural gas liquids for the year 2000. CAPITAL EXPENDITURES The Company expended approximately $102 million in 1999 compared to $139 million in 1998 for capital expenditures. These expenditures in both years represented growth projects in the Equitable Production and NORESCO segments, and replacements, improvements and additions to plant assets in the Equitable Utilities unit. Equitable Production expenditures for 1999 in the Gulf region of $40.5 million include natural gas and crude oil production assets. Equitable Production invested $29.2 million in 1999 in the Appalachian region for new coal-bed methane and conventional natural gas wells. NORESCO expended $6.0 million for international power project development, in addition to its investment in nonconsolidated subsidiaries, described below. The Utilities segment expended $25.3 million for distribution plant replacements and improvements. A total of $166 million has been authorized for the 2000 capital expenditure program, described in more detail in the segment discussions above. The Company expects to finance this program with cash generated from operations and with short-term loans. INVESTMENTS IN NONCONSOLIDATED SUBSIDIARIES The Company, within the NORESCO segment, has equity ownership interests in independent power plant (IPP) projects located domestically and in select international countries. Long-term power purchase agreements (PPAs) are signed with the customer whereby they agree to purchase the energy generated by the plant. The length of these contracts range from 5 to 30 years. The Company has invested approximately $29.3 million in these operations since January 1998. The Company's share of the earnings for this same time period is approximately $5.5 million. These projects generally are financed on a project basis with nonrecourse financings established at the foreign subsidiary level. 26
27 ACQUISITIONS AND DISPOSITIONS In December 1999, the Company acquired Carnegie Natural Gas Company and subsidiaries for $40 million, including natural gas distribution, pipeline, exploration and production operations. The Company financed this purchase with commercial paper borrowings. In February 2000, the Company acquired the Appalachian production assets of Statoil Energy Inc. for $630 million plus working capital. The Company initially funded this acquisition through commercial paper, to be replaced by a combination of financings and cash from asset sales. In March 2000, the Company agreed to merge Equitable Production - Gulf with Westport, Inc., an oil and natural gas exploration and development company based in Denver, Colorado, for a 49% ownership interest in the combined entity. The combined company intends to repay $50 million of Equitable Production - Gulf intercompany debt and replace it with third party debt. 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 to support working capital requirements during the summer months and are repaid as natural gas is sold during the heating season. 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 5.26% during 1999. The Company maintains a revolving credit agreement with a group of banks providing $500 million of available credit, which expires in 2001. In addition, in January 2000, the Company obtained an additional $500 million, 364-day revolving credit agreement to back the issuance of commercial paper. Effective February 1, 2000, the Company has the authority and credit backing to support a $1 billion commercial paper program. This program is being used to finance the acquisition of the Appalachian oil and natural gas properties of Statoil Energy, Inc. described above, as well as ongoing working capital and other short-term financing requirements. FINANCING The Company has adequate borrowing capacity to meet its financing requirements. In July 1999, the Company repaid $75 million of 7 1/2% debentures, using cash proceeds received in 1998 from the sale of its natural gas midstream operations. In 1999, the Company received proceeds of $17.0 million from the issuance of nonrecourse debt used to finance a cogeneration facility owned by a subsidiary of the Company and located in Jamaica. The note is backed by the assets of the Jamaican facility. Beginning in October 1998, the Company has undertaken a stock buyback program. Total purchases under the program of 4.7 million shares include 3.3 million shares of stock repurchased in 1999 for $101.4 million. In total, the Company has repurchased 12.7% of shares outstanding at December 31, 1997. Cash generated in all years was partially offset by the payment of the Company's dividends on common shares, which for 1999 and 1998 were $40.4 million and $43.8 million, respectively. RATE REGULATION Accounting for the operations of Equitable's Utilities segment is in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As described in Note A 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 deferred costs. 27
28 ENVIRONMENTAL MATTERS Equitable and its subsidiaries are subject to extensive federal, state and local environmental laws and regulations that affect their operations. Governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future activities. Management does not know of any environmental liabilities that will have a material effect on Equitable's financial position or results of operations. The Company has identified situations that require remedial action for which approximately $4.0 million is accrued at December 31, 1999. Environmental matters are described in Note U to the consolidated financial statements. INFLATION AND THE EFFECT OF CHANGING ENERGY PRICES The rate of inflation in the United States has been moderate over the past several years and has not significantly affected the profitability of the Company. In prior periods of high general inflation, oil and natural gas prices generally increased at comparable rates; however, there is no assurance that this will be the case in the current environment or in possible future periods of high inflation. Regulated utility operations would be required to file a general rate case in order to recover higher costs of operations. Margins in the energy marketing business in the Equitable Utilities segment are highly sensitive to competitive pressures and may not reflect the effects of inflation. The results of operations in the Company's three business segments will be affected by future changes in oil and natural gas prices and the interrelationship between oil, natural gas and other energy prices. IMPACT OF YEAR 2000 In prior years, the Company discussed the nature and progress of its plans to become Year 2000 ready. In late 1999, the Company completed its remediation and testing of systems. As a result of those planning and implementation efforts, the Company experienced no significant disruptions in mission critical information technology and non-information technology systems and believes those systems successfully responded to the Year 2000 date change. The Company expensed approximately $1.0 million during 1999 in connection with remediating its systems. The Company is not aware of any material problems resulting from Year 2000 issues, either with its products, its internal systems, or the products and services of third parties. The Company will continue to monitor its mission critical computer applications and those of its suppliers and vendors throughout the year 2000 to ensure that any latent Year 2000 matters that may arise are addressed promptly. AUDIT COMMITTEE The Audit Committee, composed entirely of outside 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 recommends the selection of independent auditors. FORWARD-LOOKING STATEMENTS Disclosures in this annual report may include forward-looking statements related to projected Company plans and expected results of operations. The Company notes that 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, development and results of the Company business include, but are not limited to, the following: weather conditions, the pace of deregulation of retail natural gas and electricity markets, the timing and extent of changes in commodity prices for natural gas and crude oil, changes in interest rates, availability of financing, the timing and extent of the Company's success in acquiring natural gas and crude oil properties and in discovering, developing and producing reserves, delays in obtaining necessary governmental approvals, the impact of competitive factors on profit margins in various markets in which the Company competes, and the successful integration of acquired companies. 28
29 ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK The Company's primary market risk exposure is the volatility of future prices for natural gas, crude oil and propane, which can affect the operating results of Equitable through the Equitable Production segment and the unregulated marketing group within the Utilities segment. The Company's use of derivatives to reduce the effect of this volatility is described in Note B to the consolidated financial statements. The Company uses simple, nonleveraged derivative instruments that are placed with major institutions whose creditworthiness is continually monitored. The Company's use of these derivative financial instruments is implemented under a set of policies approved by the Board of Directors. For commodity price derivatives used to hedge Company production, Equitable sets policy limits relative to expected production and sales levels which are exposed to price risk. The level of price exposure is limited by the value at risk limits allowed by this policy. Volumes associated with future activities, such as new drilling, recompletions and acquisitions, are not eligible for hedging. Management monitors price and production levels on essentially a continuous basis and will make adjustments to quantities hedged as warranted. In general, Equitable's strategy is to become more highly hedged at prices considered to be at the upper end of historical levels. For commodity price derivatives used to hedge marketing physical positions, the marketing group will engage in financial transactions also subject to policies that limit the net positions to specific value at risk limits. In general, this marketing group considers profit opportunities in both physical and financial positions, and Equitable's policies apply equally thereto. With respect to the energy derivatives held by the Company as of December 31, 1999, a decrease of 10% in the market price of natural gas and crude oil from the December 31, 1999 levels would decrease the fair value of the natural gas instruments by approximately $.7 million and would increase the fair value of the crude oil instruments by approximately $.5 million. A 10% decrease would have minimal impact on the fair value of the propane instruments. The above analysis of the energy derivatives utilized for risk management purposes does not include the favorable impact that the same hypothetical price movement would have on the Company and its subsidiaries' physical purchases and 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 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 options might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first. 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. 29
30 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA <TABLE> <CAPTION> PAGE REFERENCE -------------- <S> <C> Report of Independent Auditors.............................. 31 Statements of Consolidated Income for each of the three years in the period ended December 31, 1999............... 32 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1999............... 33 Consolidated Balance Sheets December 31, 1999 and 1998...... 34 & 35 Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1999......... 36 Notes to Consolidated Financial Statements.................. 37 - 59 </TABLE> 30
31 REPORT OF INDEPENDENT AUDITORS The Board of Directors and Stockholders Equitable Resources, Inc. We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 1999 and 1998, 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, 1999. Our audits also included the financial statement schedule listed in the Index at Item 14(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 generally accepted in the 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, 1999 and 1998, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 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. /s/ ERNST & YOUNG LLP -------------------------------- Ernst & Young LLP Pittsburgh, Pennsylvania February 14, 2000 31
32 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME YEARS ENDED DECEMBER 31, <TABLE> <CAPTION> 1999 1998 1997 ---------- -------- ---------- (THOUSANDS EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> Operating revenues........................................ $1,062,738 $870,628 $913,069 Cost of sales............................................. 610,659 471,609 467,163 ---------- -------- -------- Net operating revenues............................... 452,079 399,019 445,906 ---------- -------- -------- Operating expenses: Operation and maintenance............................... 80,879 82,744 104,200 Exploration............................................. 9,288 27,211 7,260 Production.............................................. 26,206 30,289 31,851 Selling, general and administrative..................... 92,229 103,563 100,328 Depreciation, depletion and amortization................ 100,722 85,170 76,032 Restructuring, impairment and other nonrecurring charges.............................................. -- 81,840 24,055 ---------- -------- -------- Total operating expenses............................. 309,324 410,817 343,726 ---------- -------- -------- Operating income (loss)................................... 142,755 (11,798) 102,180 Equity in earnings of nonconsolidated subsidiaries........ 2,863 2,667 -- Gain on sale of assets.................................... -- -- 50,120 ---------- -------- -------- Earnings (loss) from continuing operations, before interest & taxes........................................ 145,618 (9,131) 152,300 Interest charges.......................................... 37,132 40,302 34,903 ---------- -------- -------- Income (loss) before income taxes......................... 108,486 (49,433) 117,397 Income taxes (benefits)................................... 39,356 (22,381) 43,210 ---------- -------- -------- Net income (loss) from continuing operations before extraordinary loss...................................... 69,130 (27,052) 74,187 Income (loss) from discontinued operations after taxes.... -- (8,804) 3,870 Extraordinary loss after taxes -- early extinguishment of debt.................................................... -- (8,263) -- ---------- -------- -------- Net income (loss)......................................... $ 69,130 $(44,119) $ 78,057 ========== ======== ======== Earnings (loss) per share of common stock: Basic: Continuing operations, before extraordinary loss..... $ 2.03 $ (0.73) $ 2.06 Discontinued operations.............................. -- (0.24) 0.11 Extraordinary loss -- early extinguishment of debt... -- (0.22) -- ---------- -------- -------- Net income (loss).................................... $ 2.03 $ (1.19) $ 2.17 ========== ======== ======== Diluted: Continuing operations, before extraordinary loss..... $ 2.01 $ (0.73) $ 2.05 Discontinued operations.............................. -- (0.24) 0.11 Extraordinary loss -- early extinguishment of debt... -- (0.22) -- ---------- -------- -------- Net income (loss).................................... $ 2.01 $ (1.19) $ 2.16 ========== ======== ======== </TABLE> See notes to consolidated financial statements. 32
33 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS YEARS ENDED DECEMBER 31, <TABLE> <CAPTION> 1999 1998 1997 --------- --------- -------- (THOUSANDS) <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) from continuing operations, before extraordinary items..................................... $ 69,130 $ (27,052) $ 74,187 --------- --------- -------- Adjustments to reconcile net income (loss) to net cash provided by operating activities: Impairment of assets.................................. -- 75,245 13,000 Exploration expense................................... 9,288 27,211 7,260 Depreciation, depletion and amortization.............. 100,722 85,170 76,032 Gain on sale of property.............................. -- -- (50,120) Amortization of construction contract costs........... 23,100 8,271 7,925 Deferred income taxes (benefits)...................... 14,635 (29,537) 31,008 Changes in other assets and liabilities: Accounts receivable and unbilled revenues.......... 42,639 117,521 (59,015) Contract receivables............................... (25,170) 459 (4,000) Deferred purchased gas cost........................ 10,370 5,646 16,026 Prepaid expenses and other......................... (19,460) 32,353 (12,858) Accounts payable................................... (66,535) (121,396) 54,254 Deferred revenue................................... (13,867) (16,529) (22,156) Other -- net....................................... 28,543 (31,186) (28,003) --------- --------- -------- Total adjustments................................ 104,265 153,228 29,353 --------- --------- -------- Net cash provided by continuing operating activities................................... 173,395 126,176 103,540 Net cash (used in) provided by discontinued operations................................... -- (24,473) 18,321 --------- --------- -------- Net cash provided by operating activities...... 173,395 101,703 121,861 --------- --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures on continuing operations............. (101,991) (158,714) (227,360) Capital expenditures on discontinued operations........... -- (32,004) (32,835) Carnegie acquisition...................................... (40,128) -- -- Increase in investment in nonconsolidated subsidiaries.... (23,436) (17,010) (427) Proceeds from sale of property............................ 8,935 338,255 181,566 --------- --------- -------- Net cash provided by (used in) investing activities....................................... (156,620) 130,527 (79,056) --------- --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Issuance of common stock.................................. -- 2,496 6,631 Purchase of treasury stock................................ (94,615) (37,747) (28,596) Dividends paid............................................ (40,384) (43,800) (42,679) Proceeds from issuance of nonrecourse note for project financing............................................... 17,000 -- -- Purchase of debt due 2000 through 2026.................... -- (68,556) -- Proceeds from preferred trust securities.................. -- 125,000 -- Repayments and retirements of long-term debt.............. (74,972) (10,880) -- Increase (decrease) in short-term loans................... 91,783 (165,741) 76,544 --------- --------- -------- Net cash provided (used) by financing activities... (101,188) (199,228) 11,900 --------- --------- -------- Net increase (decrease) in cash and cash equivalents........ (84,413) 33,002 54,705 Cash and cash equivalents at beginning of year.............. 102,444 69,442 14,737 --------- --------- -------- Cash and cash equivalents at end of year.................... $ 18,031 $ 102,444 $ 69,442 ========= ========= ======== CASH PAID DURING THE YEAR FOR: Interest (net of amount capitalized)...................... $ 54,516 $ 46,973 $ 43,533 ========= ========= ======== Income taxes.............................................. $ 5,759 $ 15,568 $ 16,030 ========= ========= ======== </TABLE> See notes to consolidated financial statements. 33
34 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, <TABLE> <CAPTION> 1999 1998 ---------- ---------- (THOUSANDS) <S> <C> <C> ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 18,031 $ 102,444 Accounts receivable (less accumulated provision for doubtful accounts: 1999, $13,024; 1998, $9,818)........ 148,103 199,362 Unbilled revenues......................................... 46,686 41,616 Inventory................................................. 40,859 33,743 Deferred purchased gas cost............................... 29,075 39,445 Prepaid expenses and other................................ 44,084 34,832 ---------- ---------- Total current assets................................... 326,838 451,442 ---------- ---------- INVESTMENT IN NONCONSOLIDATED SUBSIDIARIES.................. 40,873 17,437 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT: Equitable Utilities....................................... 919,815 889,572 Equitable Production...................................... 1,107,345 1,041,269 NORESCO................................................... 25,368 25,922 ---------- ---------- Total property, plant and equipment.................... 2,052,528 1,956,763 Less accumulated depreciation and depletion................. 831,097 762,320 ---------- ---------- Net property, plant and equipment...................... 1,221,431 1,194,443 ---------- ---------- OTHER ASSETS: Regulatory assets......................................... 63,382 65,983 Goodwill.................................................. 64,382 68,128 Other..................................................... 72,668 63,423 ---------- ---------- Total other assets..................................... 200,432 197,534 ---------- ---------- Total................................................ $1,789,574 $1,860,856 ========== ========== </TABLE> See notes to consolidated financial statements. 34
35 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, <TABLE> <CAPTION> 1999 1998 ---------- ---------- (THOUSANDS) <S> <C> <C> LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Current portion long-term debt............................ $ -- $ 74,136 Short-term loans.......................................... 207,486 115,703 Accounts payable.......................................... 81,444 147,979 Other current liabilities................................. 140,600 104,142 ---------- ---------- Total current liabilities.............................. 429,530 441,960 ---------- ---------- LONG-TERM DEBT: Debentures and medium-term notes.......................... 281,350 281,350 Nonrecourse project financing............................. 17,000 -- ---------- ---------- Total long-term debt................................... 298,350 281,350 DEFERRED AND OTHER CREDITS: Deferred income taxes..................................... 183,896 172,676 Deferred investment tax credits........................... 16,614 17,695 Deferred revenue.......................................... 59,451 70,441 Other..................................................... 33,923 43,315 ---------- ---------- Total deferred and other credits....................... 293,884 304,127 ---------- ---------- Commitments and contingencies............................... -- -- ---------- ---------- PREFERRED TRUST SECURITIES.................................. 125,000 125,000 ---------- ---------- COMMON STOCKHOLDERS' EQUITY: Common stock, no par value, authorized 80,000 shares; shares issued: 1999 and 1998, 37,252................... 280,617 280,400 Treasury stock, shares at cost: 1999, 4,522; 1998, 1,396.................................................. (133,913) (39,298) Retained earnings......................................... 496,072 467,326 Accumulated other comprehensive income (loss)............. 34 (9) ---------- ---------- Total common stockholders' equity...................... 642,810 708,419 ---------- ---------- Total................................................ $1,789,574 $1,860,856 ========== ========== </TABLE> See notes to consolidated financial statements. 35
36 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES STATEMENTS OF COMMON STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997 <TABLE> <CAPTION> COMMON STOCK ACCUMULATED ------------------------ OTHER COMMON SHARES NO RETAINED COMPREHENSIVE STOCKHOLDERS' OUTSTANDING PAR VALUE EARNINGS INCOME EQUITY ----------- --------- --------- ------------- ------------- (THOUSANDS) <S> <C> <C> <C> <C> <C> BALANCE, DECEMBER 31, 1996........... 35,346 $223,637 $519,867 $(1,221) $ 742,283 Comprehensive income: Net income for the year 1997..... 78,057 78,057 Foreign currency translation..... 1,168 1,168 --------- Total comprehensive income....... 79,225 Dividends ($1.18 per share)........ (42,679) (42,679) Stock issued: Acquisition of subsidiary........ 2,401 68,276 68,276 Conversion of 9 1/2% debentures..................... 33 370 370 Stock-based compensation plans... 106 3,323 3,323 Dividend reinvestment plan....... 43 1,318 1,318 Treasury stock purchases........... (1,000) (28,596) (28,596) --------- Net change in common stock....... 44,691 ------ -------- -------- ------- --------- BALANCE, DECEMBER 31, 1997........... 36,929 268,328 555,245 (53) 823,520 Comprehensive income (loss): Net loss for the year 1998....... (44,119) (44,119) Foreign currency translation..... 44 44 --------- Total comprehensive loss......... (44,075) Dividends ($1.18 per share)........ (43,800) (43,800) Stock issued: Acquisition of subsidiary........ 171 5,460 5,460 Stock-based compensation plans... 56 3,990 3,990 Dividend reinvestment plan....... 40 1,071 1,071 Stock repurchase program........... (1,340) (37,747) (37,747) --------- Net change in common stock....... (27,226) ------ -------- -------- ------- --------- BALANCE, DECEMBER 31, 1998........... 35,856 241,102 467,326 (9) 708,419 Comprehensive income: Net income for the year 1999..... 69,130 69,130 Foreign currency translation..... 43 43 --------- Total comprehensive income....... 69,173 Dividends ($1.18 per share)........ (40,384) (40,384) Stock issued: Stock-based compensation plans... 220 6,959 6,959 Stock repurchase program........... (3,347) (101,357) (101,357) --------- Net change in common stock....... (94,398) ------ -------- -------- ------- --------- BALANCE, DECEMBER 31, 1999........... 32,729 $146,704 $496,072 $ 34 $ 642,810 ------ -------- -------- ------- --------- </TABLE> - --------------- Common shares authorized: 80,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding. Common shares outstanding are net of treasury stock: 1999 -- 4,522,000 shares ($133,913,000); 1998--1,396,000 shares ($39,298,000); 1997 -- 56,000 shares ($1,551,000). Retained earnings of $495,791,000 are available for dividends on, or purchase of, common stock pursuant to restrictions imposed by indentures securing long-term debt. See notes to consolidated financial statements. 36
37 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999 A. 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 interest is held (Equitable or the Company). Equitable also consolidates its interest in oil and natural gas partnerships. Equitable uses the equity method of accounting for companies where its ownership is between 20% and 50%. Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles 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 a 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 in interest charges. Inventories: Inventories, which consist of natural gas stored underground and materials and supplies, are stated at average cost. Properties, Depreciation and Depletion: Plant, property and equipment is carried at cost. Depreciation is provided on the straight-line method based on estimated service lives, ranging from 3 to 70 years except for most natural gas and crude oil production properties as explained below. The Company uses the successful efforts method of accounting for exploration and production activities. Under this method, the cost of productive wells and development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. Deferred Purchased Natural Gas Cost and Other Regulatory Assets: The Company's distribution and interstate pipelines are subject to rate regulation by state and federal regulatory commissions. Accounting for these operations is in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, the Company defers the difference between 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. Certain other costs, which will be passed through to customers under ratemaking rules for regulated operations, are deferred by the Company as regulatory assets when recovery through rates is expected. These amounts relate primarily to the accounting for income taxes. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of deferred costs. Derivative Commodity Instruments: The Company uses exchange-traded natural gas and crude oil futures contracts and options and over-the-counter (OTC) natural gas and crude oil swap agreements and options to hedge exposures to fluctuations in oil and natural gas prices and for trading purposes. At contract inception, the Company designates derivative commodity instruments as hedging or trading activities. The Company uses the deferral accounting method to account for exchange-traded derivative commodity instruments designated and effective as hedges. Under this method, changes in the market value of these hedge positions are deferred and included in other current assets and other current liabilities. These deferred realized and unrealized gains and losses are included in operating revenues when the hedged transactions occur. In the event a hedge contract is terminated early, the deferred gain or loss realized on early termination of the contract will be recognized as the hedged production occurs. The Company uses the settlement method to account for OTC swap agreements and options designated and effective as hedges. Under this method, gains or losses associated with the contract are recognized at the time the hedged production occurs. Premiums on option contracts are deferred in other current assets and recognized in operating revenues over the option term. 37
38 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Transactions that are not designated and effective as hedges are marked to market. Cash flows from derivative contracts are considered operating activities. In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133." This statement delays the required implementation for the Company until 2001. The Company has not yet determined when it will adopt the provisions of this statement, which may be implemented at the beginning of any fiscal quarter. SFAS No. 133 will require the Company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of derivatives will either be offset against the change in fair value of the hedged assets, liabilities or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be immediately recognized in earnings. The Company has not yet determined what the effect of SFAS No. 133 will be on the earnings and financial position of the Company. 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 1999, 1998 and 1997 of $4.6 million, $2.7 million and $4.1 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 acquired. Goodwill is amortized on a straight-line basis over a period of 20 years. The Company assesses the impairment of goodwill related to consolidated subsidiaries whenever events or changes in circumstances indicate that the carrying value may not be recoverable. A determination of impairment (if any) is made based on estimates of future cash flows. In instances where goodwill has been recorded for assets that are subject to an impairment loss, the carrying amount of the goodwill is eliminated before any reduction is made to the carrying amounts of impaired long-lived assets and identifiable intangibles. Stock-Based Compensation: The Company has elected to follow Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for stock options and awards. Accordingly, compensation cost for stock options and awards is measured as the excess, if any, of the quoted market price of the Company's stock at the date of grant over the exercise price of the stock option or award. Revenue Recognition: Revenues for regulated natural gas sales to retail customers are recognized as service is rendered, including an accrual for unbilled revenues from the date of each meter reading to the end of the accounting period. Revenue is recognized for exploration and 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. Revenues from activities classified as energy trading are recognized immediately. The Company recognizes revenue from shared energy savings contracts as energy savings are measured and verified. Revenue received from customer contract termination payments is recognized when received. Revenue from other long-term contracts, such as turnkey contracts, is recognized on a percentage-of-completion basis, determined using the cost-to-cost method. Any maintenance revenues are recognized as related services are performed. 38
39 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Sales of Receivables: The Company sells some amounts due from customers to financial institutions. At the time of the transfer, the amounts due from the customer are recognized as revenue, the transfer is accounted for as the sale of a receivable, the receivable is no longer reflected in the financial statements and any related deferred costs are charged to operations. Income Taxes: The Company files a consolidated federal income tax return. The current provision for income taxes represents amounts paid or estimated to be payable. Deferred income tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities. 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. 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. Earnings Per Share (EPS): "Basic" EPS excludes dilution and is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. "Diluted" EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted to common stock. 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 in deciding how to allocate resources. Operating segments are evaluated on their contribution to the Company's consolidated results, based on earnings before interest and taxes. Interest charges, income taxes and certain corporate office expenses are managed on a consolidated basis and are allocated pro forma to operating segments. Reclassification: Certain previously reported amounts have been reclassified to conform with the 1999 presentation. B. DERIVATIVE COMMODITY INSTRUMENTS The Company uses exchange-traded natural gas, crude oil and propane futures contracts, options and OTC natural gas, crude oil and propane swap agreements and options (collectively, derivative contracts) to hedge exposures to fluctuations in natural gas, oil and propane prices and for trading purposes. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price. 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 of commodities. OTC arrangements require settlement in cash. HEDGING ACTIVITIES The Company is exposed to risk from fluctuations in energy prices in the normal course of business. The Company uses derivative contracts to hedge exposures to natural gas, oil and propane price changes. The following table summarizes the absolute notional quantities of the derivative contracts held for purposes other than trading at December 31, 1999 and 1998. The open futures and options contracts at year-end 1999 have maturities extending through December 2000, while the swap agreements have maturities extending through March of 2001. At December 31, 1998, the open futures and options contracts had maturities extending through 39
40 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 B. DERIVATIVE COMMODITY INSTRUMENTS (CONTINUED) October 2000 and December 1999, respectively, while the swap agreements had maturities extending through May of 2001. <TABLE> <CAPTION> ABSOLUTE NOTIONAL DEFERRED QUANTITY GAIN/LOSS ------------------ ---------------- 1999 1998 1999 1998 ------- ------- ------ ------ <S> <C> <C> <C> <C> (BCF EQUIVALENT) (MILLIONS) Natural gas Futures............................................... 18.8 41.5 $ (0.8) $ (2.1) Swaps................................................. 71.2 300.8 (2.9) (11.6) Options............................................... 17.0 72.9 0.8 1.0 ----- ----- ------ ------ Totals.............................................. 107.0 415.2 $ (2.9) $(12.7) ----- ----- ------ ------ (MBLS EQUIVALENT) (MILLIONS) Oil Futures............................................... 0.2 -- $ (0.7) $ -- Swaps................................................. 0.8 -- (0.5) -- Options............................................... 0.3 -- (0.9) -- ----- ----- ------ ------ Totals.............................................. 1.3 -- $ (2.1) $ -- ----- ----- ------ ------ (MBLS EQUIVALENT) (MILLIONS) Propane Futures............................................... -- -- $ -- $ -- Swaps................................................. 0.8 -- (0.3) -- Options............................................... 0.1 -- -- -- ----- ----- ------ ------ 0.9 -- $ (0.3) $ -- ----- ----- ------ ------ </TABLE> Deferred realized amounts from hedge transactions were a $.1 million gain at December 31, 1999, and a $.6 million gain at December 31, 1998. The Company recognized net losses on its hedging activities of $8.5 million, $3.0 million and $9.8 million in 1999, 1998 and 1997, respectively. These losses are offset when the underlying products are sold. 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. 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. TRADING ACTIVITIES The Company conducts trading activities through its deregulated marketing group. The function of the Company's trading business is to contribute to the Company's earnings by taking market positions within strictly defined trading limits. At December 31, 1999, the absolute notional quantities of the futures, swaps and physical contracts held for trading purposes were 1.4 Bcfe, 9.2 Bcfe and 17.0 Bcfe, respectively. There were no outstanding derivative contracts held for trading purposes at December 31, 1998. 40
41 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 B. DERIVATIVE COMMODITY INSTRUMENTS (CONTINUED) The table below sets forth the end of period fair value and average fair value during the year for all the derivative contracts held for trading purposes. <TABLE> <CAPTION> 1999 1997 --------------------- ---------------------- ASSETS LIABILITIES ASSETS LIABILITIES ------ ----------- ------- ----------- (THOUSANDS) (THOUSANDS) <S> <C> <C> <C> <C> Fair value at December 31............... $2,695 $2,914 $82,912 $79,012 Average fair value...................... $2,583 $2,837 $12,161 $10,509 </TABLE> Trading activity resulted in net losses of $.6 million for 1999. There was no trading activity in 1998. In 1997 trading activity resulted in a net gain of $1.1 million. C. ASSET IMPAIRMENT AND OTHER NONRECURRING ITEMS The Company's 1998 and 1997 results of operations include several significant nonrecurring items which are included in operating expense. In December 1998, as a result of a sustained decrease in natural gas and crude oil prices and a change in management's objectives in the Gulf of Mexico, the Company recognized a write-down in the carrying value of crude oil and natural gas production assets of $36.9 million. To improve the efficiency of Appalachian production operations, the Company obtained authority in 1999 from the Federal Energy Regulatory Commission (FERC) to decertify the pipeline facilities of Kentucky West Virginia Gas Company, LLC (Kentucky West). In decertifying the pipeline, the Company determined that not all costs would be collectible in rates and reduced regulatory and other assets by $9.2 million, including $3.6 million in Equitable Utilities and $5.6 million in Equitable Production. In addition, the Company implemented a fundamental restructuring of its utility, nonregulated retail sales and headquarters groups. This process included a voluntary workforce reduction incentive offer to reduce staff, the closing or consolidation of several offices, reconfiguration of management information systems, the realignment of many administrative functions to specific operating segments and the curtailment of several auxiliary business ventures. Expenses associated with these initiatives totaled $35.7 million including $8.1 million in the utility group, $2.1 million in the production group, $2.7 million in energy services, $3.0 million in the energy sales unit and $19.8 million in headquarters. In June 1997, an evaluation of the carrying value of long-lived assets resulted in a write-down of the Utilities segment's investment in the Avoca bedded salt natural gas storage project, for which the Company recognized a $13 million charge. In September 1997, the Company recorded an additional charge of $10.7 million related to evaluation and reduction of headquarters and noncore business functions. D. DIRECT BILLING AND OTHER SETTLEMENTS Kentucky West received FERC approval of settlement agreements with all customers for direct billing to recover the higher Natural Gas Policy Act (NGPA) prices, which the FERC had denied on natural gas produced from exploration and production properties between 1978 and 1983. The portion of the settlement with the Equitable Gas Company division was subject to Pennsylvania Public Utility Commission (PUC) review. The PUC approved Equitable Gas Company's collection of $2.6 million in September 1998 and $7.8 million in September 1997 related to the direct billing settlement. These amounts are recognized as other operating revenues in the production segment for 1998 and 1997. 41
42 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 E. DISCONTINUED OPERATIONS In April 1998, management adopted a formal plan to sell the Company's natural gas midstream operations. The operations included an integrated natural gas gathering, processing and storage system in Louisiana and a natural gas and electricity trading and marketing business based in Houston. The financial statements for all periods have been restated to classify these as discontinued operations. In December 1998, the Company completed the sale of these operations to various parties for $338.3 million, which included working capital adjustments. Net income (loss) from discontinued operations was $(8.8) million and $3.9 million for the years ended December 31, 1998 and 1997, respectively. The net loss in 1998 reflects an after-tax gain on the sale of $10.1 million. The net income (loss) for each year was reported net of income tax expense (benefit) of $(0.2) million and $3.2 million in 1998 and 1997, respectively. Interest expense allocated to discontinued operations was $7.4 million and $7.2 million for the years ended December 31, 1998 and 1997, respectively. F. SALE OF PROPERTY In July 1997, the Company entered into agreements with five parties for the sale of the Company's crude oil and natural gas properties in the western United States and Canada. The sales were completed in September and October for an aggregate cash sales price of $170 million. In October 1997, the Company sold its Union Drilling division, a contract drilling company, for $7 million. These sales resulted in gains of $52 million in 1997. G. ACQUISITIONS In December 1999, the Company acquired Carnegie Natural Gas Company and subsidiaries (Carnegie) for $40 million, including transaction costs. The Carnegie operations include natural gas distribution and pipeline businesses which will be integrated into those divisions of the Company's Utilities segment, as well as exploration and production businesses which will be integrated into the Production segment. Carnegie operates more than 1,000 natural gas wells in Pennsylvania and West Virginia and supplies approximately 8,000 industrial, commercial and residential customers. No goodwill was recorded in connection with the acquisition, which was accounted for under the purchase method of accounting. In July 1997, the Company acquired Northeast Energy Services, Inc. (NORESCO) in exchange for a combination of 2.1 million shares of the Company's stock valued at approximately $67 million and $10 million in cash, including transaction costs. NORESCO is a provider of comprehensive energy efficiency systems and services for commercial, industrial, government and institutional customers. NORESCO's primary assets are accounts receivable from customers and deferred contract costs, which are included in other assets in the consolidated balance sheets. The transaction was treated as a purchase for accounting purposes. The Company recorded goodwill of $57 million which is being amortized over 20 years. The $67 million noncash portion of the acquisition is excluded from capital expenditures in the 1997 cash flows statement. In 1997, the NORESCO segment also acquired Scallop Thermal Industries (Scallop) and Lighting Management, Inc. (LMI) for a total cost of $4 million. These acquisitions were accounted for under the purchase method of accounting. The effect of each of these acquisitions, individually and aggregated by year of purchase, is not material to the results of operations or financial position of Equitable, and therefore, pro forma financial information is not presented. 42
43 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 H. INCOME TAXES The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities. <TABLE> <CAPTION> DECEMBER 31, -------------------- 1999 1998 -------- -------- (THOUSANDS) <S> <C> <C> Deferred tax liabilities (assets): Exploration and development costs expensed for income tax reporting.............................................. $104,628 $ 86,742 Tax depreciation in excess of book depreciation........... 163,755 163,788 Regulatory temporary differences.......................... 25,069 26,095 Deferred purchased natural gas cost....................... 6,710 13,594 Deferred revenues/expenses................................ (14,507) (14,324) Alternative minimum tax................................... (50,114) (58,517) Investment tax credit..................................... (6,565) (6,998) Uncollectible accounts.................................... (6,450) (5,583) Postretirement benefits................................... (3,982) (3,971) Other..................................................... (21,836) (13,750) -------- -------- Total (including amounts classified as current liabilities of $12,812 for 1999 and $14,602 for 1998)................................................ $196,708 $187,076 ======== ======== </TABLE> As of December 31, 1999 and 1998, $59.1 million and $62.1 million, respectively, of the net deferred tax liabilities are related to rate-regulated operations and have been deferred as regulatory assets. Income tax expense (benefit) is summarized as follows: <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, ------------------------------ 1999 1998 1997 ------- -------- ------- (THOUSANDS) <S> <C> <C> <C> Current: Federal............................................. $23,758 $ 5,331 $10,333 State............................................... 916 339 717 Foreign............................................. 47 -- 232 ------- -------- ------- Deferred: Federal............................................. 14,756 (22,033) 27,756 State............................................... (121) (7,504) 3,252 Foreign............................................. -- 1,486 920 ------- -------- ------- Total............................................ $39,356 $(22,381) $43,210 ======= ======== ======= </TABLE> 43
44 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 H. INCOME TAXES (CONTINUED) Provisions for income taxes differ from amounts computed at the federal statutory rate of 35% on pretax income. The reasons for the difference are summarized as follows: <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, ------------------------------ 1999 1998 1997 ------- -------- ------- (THOUSANDS) <S> <C> <C> <C> Tax at statutory rate................................. $37,970 $(17,301) $41,089 State income taxes.................................... 517 (4,657) 2,580 Nonconventional fuels tax credit...................... (817) (1,199) (816) Other................................................. 1,686 776 357 ------- -------- ------- Income tax expense (benefit)........................ $39,356 $(22,381) $43,210 ======= ======== ======= Effective tax rate (benefit).......................... 36.3% (45.3)% 36.8% ======= ======== ======= </TABLE> The consolidated federal income tax liability of the Company has been settled through 1994. The Company has not provided any U.S. tax on undistributed earnings of foreign subsidiaries or joint ventures that are reinvested indefinitely outside the United States. At December 31, 1999, consolidated retained earnings of the Company included approximately $5.1 million of undistributed earnings from these investments. I. INVESTMENTS IN NONCONSOLIDATED SUBSIDIARIES The NORESCO segment, through its energy infrastructure division, has investments in unconsolidated partnerships. These investments represent equity ownership interests in independent power plant (IPP) projects located domestically in the United States as well as in selected international countries. <TABLE> <CAPTION> DECEMBER 31, ------------------ EQUITY INVESTEES LOCATION OWNERSHIP 1999 1998 - ------------------------------- ---------- --------- ------- ------- (THOUSANDS) <S> <C> <C> <C> <C> IGC/ERI Pan-Am Thermal Panama 50% $14,863 $ 510 Capital Center Energy USA 50% 12,779 4,401 Petroelectrica de Panama Panama 45% 9,228 8,807 Dona Julia Costa Rica 24% 3,235 2,958 Other USA Various 768 761 ------- ------- $40,873 $17,437 ======= ======= </TABLE> IPP projects which NORESCO and its partners develop, construct and operate are the result of specific needs of private or governmental entities to secure power that is more cost effective and reliable than the current source of power as well as to meet the growing energy demands of many international countries. Long-term power purchase agreements are signed with the customer whereby they agree to purchase the energy generated by the plant. The length of these contracts ranges from 5 to 30 years. The Company has invested approximately $29.3 million in these operations since January 1998 and the Company's ownership share of the earnings for this same time period is approximately $5.5 million. All projects have been completed within the NORESCO segment using nonrecourse financing at the subsidiary level. Foreign investments represent $27.3 million, or 67%, of investments in nonconsolidated subsidiaries. In addition, $20 million of fixed assets is included in NORESCO's property, plant and equipment balance at December 31, 1999, related to an independent power project located in Jamaica, of which NORESCO is a majority owner. Total Company investments located in foreign countries was $47.3 million at December 31, 1999. 44
45 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 J. INTANGIBLE ASSETS From 1995 to 1998, the Company acquired several energy services companies. These transactions were treated as purchases for accounting purposes, with goodwill being recorded. Amortization of the goodwill is provided on the straight-line method over a life of 20 years. Accumulated amortization at December 31, 1999 and 1998 was $10,011 and $6,265, respectively. For the years ended December 31, 1999, 1998 and 1997, amortization expense, included in depreciation, depletion and amortization, was $3,746, $3,858 and $2,214, respectively. K. SHORT-TERM LOANS Maximum lines of credit available to the Company were $500 million during 1999, 1998 and 1997. The Company is not required to maintain compensating bank balances. Commitment fees averaging one-tenth of one percent were paid to maintain credit availability. At December 31, 1999, short-term loans consisted of $207.2 million of commercial paper at a weighted average annual interest rate of 5.95% and the subsidiary note for project financing described below. At December 31, 1998, short-term loans consisted of $115.7 million of commercial paper at a weighted average annual interest rate of 5.02%. The maximum amount of outstanding short-term loans was $208 million in 1999, $315.7 million in 1998, and $302.5 million in 1997. The average daily total of short-term loans outstanding was approximately $127.9 million during 1999, $191.7 million during 1998, and $229.6 million during 1997; weighted average annual interest rates applicable thereto were 5.26% in 1999, 5.0% in 1998, and 5.7% in 1997. L. LONG-TERM DEBT <TABLE> <CAPTION> DECEMBER 31, -------------------- 1999 1998 -------- -------- (THOUSANDS) <S> <C> <C> 7 1/2% debentures, due July 1, 1999 ($75,000 principal amount, net of unamortized original issue discount)........................................ $ -- $ 74,136 7 3/4% debentures, due July 15, 2026........................ 115,000 115,000 Medium-term notes: 8.0% to 9.0% Series A, due 2001 thru 2021................. 72,850 72,850 6.5% to 7.6% Series B, due 2003 thru 2023................. 75,500 75,500 6.8% to 7.6% Series C, due 2007 thru 2018................. 18,000 18,000 -------- -------- 281,350 355,486 Less debt payable within one year........................... -- 74,136 -------- -------- Total debentures and medium-term notes................. 281,350 281,350 Nonrecourse note for project financing...................... 17,000 -- -------- -------- Total long-term debt................................... $298,350 $281,350 ======== ======== </TABLE> In 1998, as a result of the sale of the Company's natural gas midstream operations, the Company repurchased and retired $35.0 million of 7 3/4% debentures and $22.2 million of Series A Medium-Term Notes. Premiums paid were $12.7 million, recognized net of income tax benefits, as an extraordinary loss on early extinguishment of debt in 1998 of $8.3 million. During 1999, a subsidiary of the Company issued a $17 million 9.25% nonrecourse note for project financing. The proceeds of this note were used to fund the operations of an independent power plant located in St. Catherine, Jamaica. Interest payments related to this note are due quarterly. 45
46 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 L. LONG-TERM DEBT (CONTINUED) At December 31, 1999, the Company has the ability to issue $150 million of additional long-term debt under the provisions of shelf registrations filed with the Securities and Exchange Commission. Interest expense on long-term debt amounted to $35.2 million in 1999, $34.9 million in 1998, and $35.1 million in 1997. Aggregate maturities of long-term debt will be none in 2000, $10.1 million in 2001, none in 2002, $24.3 million in 2003 and $20.5 million in 2004. M. DEFERRED REVENUE In 1995, the Company sold an interest in certain Appalachian natural gas properties, the production from which qualifies for nonconventional fuels tax credit. The Company retained an interest in the properties that will increase based on performance. As such, the proceeds of $133.5 million were recorded as deferred revenues and are being recognized in income as financial targets are achieved. N. TRUST PREFERRED CAPITAL SECURITIES In April 1998, $125 million of 7.35% Trust Preferred Capital Securities were issued. The capital securities were issued through a subsidiary trust, Equitable Resources Capital Trust I, established for the purpose of issuing the capital securities and investing the proceeds in 7.35% Junior Subordinated Debentures issued by the Company. The capital securities have a mandatory redemption date of April 15, 2038; however, at the Company's option, the securities may be redeemed on or after April 23, 2003. Proceeds were used to reduce short-term debt outstanding. Interest expense for the years ended December 31, 1999 and December 31, 1998 includes $9.2 million and $6.3 million, respectively, of preferred dividends related to the trust preferred capital securities. O. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS The Company has pension and other postretirement benefit plans covering certain Utilities segment employees. Plans covering union members generally provide benefits of stated amounts for each year of service. Plans covering salaried utility employees use a benefit formula which is based upon employee compensation and years of service. 46
47 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 O. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED) The following table sets forth the pension and other benefit plans' funded status and amounts recognized for those plans in the Company's consolidated balance sheets: <TABLE> <CAPTION> PENSION BENEFITS OTHER BENEFITS -------------------- ------------------ 1999 1998 1999 1998 -------- -------- ------- ------- (THOUSANDS) <S> <C> <C> <C> <C> Change in benefit obligation: Benefit obligation at beginning of year........ $148,493 $143,440 $43,491 $40,077 Service cost................................... 2,294 2,177 297 334 Interest cost.................................. 9,488 9,933 3,002 2,759 Amendments..................................... 5,038 323 582 -- Actuarial (gain) loss.......................... (9,513) 10,017 (577) 2,983 Benefits paid.................................. (9,726) (9,319) (4,866) (4,168) Expenses paid.................................. (558) (205) -- -- Curtailments................................... (12) 2,519 -- -- Settlements.................................... (22,267) (11,362) -- -- Special termination benefits................... -- 970 -- 1,506 -------- -------- ------- ------- Benefit obligation at end of year........... 123,237 148,493 41,929 43,491 -------- -------- ------- ------- Change in plan assets: Fair value of plan assets at beginning of year........................................ 177,205 164,801 8,454 6,274 Actual return on plan assets................... 13,958 31,867 407 368 Employer contribution.......................... 91 1,632 219 1,812 Benefits paid.................................. (9,726) (9,319) (3,632) -- Expenses paid.................................. (558) (205) -- -- Settlements.................................... (22,151) (11,571) -- -- -------- -------- ------- ------- Fair value of plan assets at end of year.... 158,819 177,205 5,448 8,454 -------- -------- ------- ------- Funded status.................................... 35,582 28,712 (36,481) (35,037) Unrecognized net actuarial (gain) loss........... (31,733) (26,885) 14,988 16,595 Unrecognized prior service cost (credit)......... 14,825 13,125 410 (140) Unrecognized initial net (asset) obligation...... (436) (819) 12,420 13,376 -------- -------- ------- ------- Net asset (liability) recognized............ $ 18,238 $ 14,133 $(8,663) $(5,206) ======== ======== ======= ======= Weighted-average assumptions as of December 31: Discount rate.................................. 7.75% 6.75% 7.75% 6.75% Expected return on plan assets................. 10.00% 10.00% 10.00% 7.50% Rate of compensation increase.................. 4.50% 4.50% 4.50% 4.50% </TABLE> For measurement purposes, a 5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 1999. The rate was assumed to decrease gradually to 4% for 2002 and remain at that level thereafter. The pension asset of $18,238 at December 31, 1999 and $14,133 at December 31, 1998 is included in prepaid expenses and other current assets in the consolidated balance sheets. The accrued liability for other postretirement benefits of $8,663 at December 31, 1999 and $5,206 at December 31, 1998 is included in other current liabilities. 47
48 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 O. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (CONTINUED) The Company's costs related to defined benefit pension and other benefit plans comprised the following: <TABLE> <CAPTION> PENSION BENEFITS OTHER BENEFITS ------------------------------ ------------------------ 1999 1998 1997 1999 1998 1997 -------- -------- -------- ------ ------ ------ (THOUSANDS) <S> <C> <C> <C> <C> <C> <C> Components of net periodic benefit cost: Service cost........................ $ 2,294 $ 2,177 $ 2,227 $ 297 $ 334 $ 254 Interest cost....................... 9,488 9,933 10,280 3,002 2,759 2,898 Expected return on plan assets...... (13,048) (13,377) (13,254) (898) (522) (483) Amortization of prior service cost............................. 1,823 1,579 1,441 31 (15) (214) Amortization of initial net (asset) obligation....................... (333) (390) (422) 955 986 985 Recognized net actuarial (gain) loss............................. 90 3 (30) 921 749 617 Divestitures........................ -- -- -- -- (1,719) -- Special termination benefits........ -- 970 1,139 -- 1,506 -- Settlement (gain) loss.............. (5,781) (2,295) (4,016) -- -- -- Curtailment loss.................... 1,453 319 587 -- 419 -- -------- -------- -------- ------ ------ ------ Net periodic benefit cost........ $ (4,014) $ (1,081) $ (2,048) $4,308 $4,497 $4,057 ======== ======== ======== ====== ====== ====== </TABLE> 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 $1,336, $1,336 and $0, respectively, as of December 31, 1999 and $31,695, $31,695 and $28,426, respectively, as of December 31, 1998. 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: <TABLE> <CAPTION> ONE-PERCENTAGE POINT ONE-PERCENTAGE POINT INCREASE DECREASE ------------------------ ------------------------ 1999 1998 1997 1999 1998 1997 ------ ------ ------ ------- ------- ---- (THOUSANDS) <S> <C> <C> <C> <C> <C> <C> Effect on total of service and interest cost components.......................... $ 218 $ 188 $ 247 $ (207) $ (177) $-- Effect on postretirement benefit obligation............................... 2,105 2,316 2,983 (2,815) (2,238) -- </TABLE> As of December 31, 1999, approximately $1.5 million of the accrued postretirement benefits related to rate-regulated operations have been deferred as regulatory assets. Rate recovery requires the Company to place agreed upon amounts in trust when collected in rates until such time as they are applied to retiree benefits or returned to ratepayers. Trust assets consist principally of equity and debt securities. As of January 1, 1997, the Company amended its 401(k) employee savings plan for salaried employees to provide a base Company contribution to that plan for employees no longer eligible for defined benefit plans. In addition, during 1997 the present value of these employees' future retirement benefits under the defined benefit plans could be rolled over to the 401(k) plan, at the employee's option, or used to purchase an annuity. Expense recognized by the Company related to this and other 401(k) savings plans totaled $2.3 million in 1999, $3.5 million in 1998, and $3.9 million in 1997. 48
49 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 P. COMMON STOCK AND EARNINGS PER SHARE COMMON STOCK RESERVE At December 31, 1999, shares of Equitable's authorized and unissued common stock were reserved as follows: <TABLE> <CAPTION> (THOUSANDS) <S> <C> Possible future acquisitions............................. 6,607 Stock compensation plans................................. 4,892 ------ Total............................................... 11,499 ====== </TABLE> EARNINGS PER SHARE Basic EPS is computed by dividing income (loss) from continuing operations before extraordinary loss by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing income (loss) from continuing operations before extraordinary loss, 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 and, in years prior to 1998, the assumed conversion of then-outstanding convertible debentures. The computation of basic and diluted earnings (loss) per common share from continuing operations is shown in the table below: <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, ------------------------------------ 1999 1998 1997 --------- ---------- --------- (THOUSANDS EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> BASIC EARNINGS (LOSS) PER COMMON SHARE: Net income (loss) from continuing operations, before extraordinary item, applicable to common stock......... $69,130 $(27,052) $74,187 Average common shares outstanding......................... 34,044 36,833 36,003 Basic earnings (loss) per common share from continuing operations, before extraordinary item.................. $ 2.03 $ (0.73) $ 2.06 DILUTED EARNINGS (LOSS) PER COMMON SHARE: Net income (loss) from continuing operations, before extraordinary item, applicable to common stock (a)..... $69,130 $(27,052) $74,190 Average common shares outstanding......................... 34,044 36,833 36,003 Potentially dilutive securities: Stock options and awards (b)........................... 293 -- 109 Common shares issuable upon conversion of 9 1/2% convertible debentures........................ -- -- 4 ------- -------- ------- Total................................................ 34,337 36,833 36,116 Diluted earnings (loss) per common share from continuing operations, before extraordinary item.................. $ 2.01 $ (0.73) $ 2.05 </TABLE> - --------------- (a) The after-tax benefit of interest expense on the assumed conversion of the 9 1/2% convertible debentures was $3,000 in 1997. 49
50 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 P. COMMON STOCK AND EARNINGS PER SHARE (CONTINUED) (b) Options to purchase 12,000 and 284,000 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 1999 and 1997, respectively. Q. STOCK-BASED COMPENSATION PLANS LONG-TERM INCENTIVE PLANS The Company's 1994 and 1999 Long-Term Incentive 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 plan, 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 plan exceed 1,725,500 and 3,000,000 shares, respectively. Options granted under the plans expire 5 to 10 years from the date of grant and some contain vesting provisions which are based upon Company performance. Also reflected in the option tables below are options assumed in conjunction with the NORESCO acquisition in July 1997. All outstanding options granted under NORESCO's 1990 Incentive Stock Option Plan were converted by Equitable to nonqualified stock options with the right to receive, upon exercise of the option, the same Equitable stock and cash that shareholders of NORESCO received in the acquisition. As a result of this conversion, 872,000 NORESCO stock options were converted to 256,400 Equitable stock options with the exercise price per share proportionately adjusted. The adjusted exercise prices of these stock options range from $5.1012 to $5.9516 per share. The acquisition also accelerated the vesting period of these options, the latest of which expire in 2006. During 1999, 11,000 stock options were exercised under this plan, with 13,000 outstanding at December 31, 1999. Pro forma information regarding net income and earnings per share for options granted is required by SFAS No. 123, "Accounting for Stock-Based Compensation," and has been determined as if the Company had accounted for its employee stock options under the fair value method of SFAS 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 1999, 1998 and 1997, respectively. <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, -------------------------------------------------- 1999 1998 1997 -------------- -------------- -------------- <S> <C> <C> <C> Risk-free interest rate (range).......... 4.75% to 6.41% 4.80% to 5.63% 5.71% to 5.79% Dividend yield........................... 3.35% 4.06% 3.96% Volatility factor........................ .216 0.173 0.132 Weighted average expected life of options................................ 7 years 4 years 1.25 years Options granted.......................... 1,050,200 1,014,900 339,100 Weighted average fair market value of options granted during the year........ $7.16 $3.91 $1.93 </TABLE> The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's 50
51 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 Q. STOCK-BASED COMPENSATION PLANS (CONTINUED) opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. The amount of estimated expense that would have been recognized under SFAS No. 123 is not considered material to the financial statements in any of the years presented. <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, ----------------------------------- 1999 1998 1997 --------- --------- --------- <S> <C> <C> <C> Options outstanding January 1............................ 1,258,185 758,534 948,650 Granted.................................................. 1,050,200 1,014,900 339,100 Forfeitures.............................................. (452,900) (453,257) (348,800) Exercised................................................ (165,922) (61,992) (180,416) --------- --------- --------- Options outstanding December 31.......................... 1,689,563 1,258,185 758,534 ========= ========= ========= </TABLE> Options outstanding at December 31, 1999 include 544,863 exercisable at that date. <TABLE> <CAPTION> 1999 1998 1997 --------------- --------------- --------------- <S> <C> <C> <C> At December 31: Prices of options outstanding........... $5.10 to $37.88 $5.10 to $34.63 $5.10 to $36.50 Average option price.................... $29.58 $29.26 $28.02 </TABLE> On September 5, 1997, the Company granted 106,127 stock awards from the 1994 Long-Term Incentive Plan for the Executive Retention Program. This program was established to provide additional incentive benefits to retain senior executive employees of the Company. The vesting of these awards is contingent on attainment of specific stock price targets and the continued employment of the participants until January 1, 2001. In 1998 and 1999, the Company granted 25,000 and 128,000 additional stock awards, respectively, from this Long-Term Incentive Plan to key executives. The fair value of these awards was estimated at the date of grant utilizing a Black-Scholes pricing model and the same assumptions as listed above and would result in compensation expense not materially different from that recorded by the Company under APB Opinion No. 25. Compensation expense recorded by the Company related to stock awards was $4.6 million in 1999, $1.0 million in 1998 and $0.3 million in 1997. NONEMPLOYEE DIRECTORS' STOCK INCENTIVE PLANS The Company's 1994 and 1999 Nonemployee Directors' Stock Incentive Plans provide for the granting of up to 80,000 and 300,000 shares, respectively, of common stock in the form of stock option grants and restricted stock awards to non-employee 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 5-10 years after date of grant. At December 31, 1999, 70,000 options were outstanding at prices ranging from $28.38 to $34.63 per share and 6,000 options had been exercised under these plans. R. 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 estimated fair value of long-term debt described in Note L at December 31, 1999 and 1998 is $294.4 million and $391.2 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity. 51
52 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 R. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED) The estimated fair value of liabilities for derivative commodity instruments described in Note B, excluding trading activities which are marked-to-market, was $(5.3) million and $(12.7) million at December 31, 1999 and 1998, respectively. S. CONCENTRATIONS OF CREDIT RISK Revenues and related accounts receivable from the Equitable Production segment's operations are generated primarily from the sale of produced natural gas to utility and industrial customers located mainly in the Appalachian area, the sale of crude oil to refinery customers in the Appalachian area, the sale of produced natural gas liquids to a refinery customer in Kentucky and transportation of natural gas in Kentucky and Virginia. The Equitable Utilities segment's operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to more than 278,000 residential, commercial and industrial customers located in southwest Pennsylvania and parts of West Virginia and Kentucky; 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 nine mid-Atlantic and northeastern states; and the nationwide marketing of natural gas to brokers and large volume utility and industrial customers. Under state regulations, the utility is required to provide continuous natural gas service to residential customers during the winter heating season. The NORESCO segment's operating revenues and related accounts receivable are generated from cogeneration and power plant development facilities in several U.S. and Latin American markets, and performance contracting for commercial, industrial and institutional customers and various government facilities including military facilities throughout the United States. The Company is not aware of any significant credit risks which have not been recognized in provisions for doubtful accounts. T. FINANCIAL INFORMATION BY BUSINESS SEGMENT The Company reports operations in three segments which reflect its lines of business. The Equitable Utilities segment's activities are comprised of the operations of the Company's state-regulated local distribution company, natural gas transportation, storage and marketing activities involving the Company's interstate natural gas pipelines, and supply and transportation services for the natural gas and electricity markets. The Equitable Production segment's activities are comprised of the exploration, development, production, gathering and sale of natural gas and oil, and the extraction and sale of natural gas liquids. NORESCO segment's activities are comprised of cogeneration and power plant development, the development and implementation of energy and water efficiency programs, performance contracting and central facility plant operations. During 1999, the structure of the Company's internal organization changed, causing the composition of the reportable segments to change. Segment information for prior periods has been restated to conform to this change. Operating segments are evaluated on their contribution to the Company's consolidated results, based on earnings before interest and taxes. Interest charges and income taxes are managed on a consolidated basis and allocated pro forma to operating segments. Headquarters costs are billed to operating segments based on a fixed allocation of the annual headquarters operating budget. Differences between budget and actual headquarters expenses are not allocated to operating segments, but included as a reconciling item to consolidated earnings from continuing operations. 52
53 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 T. FINANCIAL INFORMATION BY BUSINESS SEGMENT (CONTINUED) Substantially all of the Company's operating revenues, net income from continuing operations and assets are generated or located in the United States of America. The financial information by business segment in the following tables excludes amounts related to discontinued operations. <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, -------------------------------------- 1999 1998 1997 ---------- ---------- ---------- (THOUSANDS) <S> <C> <C> <C> REVENUES FROM EXTERNAL CUSTOMERS: Equitable Utilities................................. $ 703,969 $ 580,767 $ 668,806 Equitable Production................................ 189,136 180,368 191,473 NORESCO............................................. 169,633 109,493 52,790 ---------- ---------- ---------- Total.......................................... $1,062,738 $ 870,628 $ 913,069 ========== ========== ========== INTERSEGMENT REVENUES: Equitable Utilities................................. $ 107,906 $ 71,257 $ 46,077 Equitable Production................................ 22,685 20,111 59,923 ---------- ---------- ---------- Total.......................................... $ 130,591 $ 91,368 $ 106,000 ========== ========== ========== DEPRECIATION, DEPLETION AND AMORTIZATION: Equitable Utilities................................. $ 35,596 $ 20,570 $ 19,778 Equitable Production................................ 58,565 56,380 50,418 NORESCO............................................. 6,078 4,300 2,775 Headquarters........................................ 483 3,920 3,061 ---------- ---------- ---------- Total.......................................... $ 100,722 $ 85,170 $ 76,032 ========== ========== ========== SEGMENT PROFIT (LOSS): Equitable Utilities................................. $ 80,641 $ 32,174 $ 39,507 Equitable Production................................ 54,616 (24,344) 122,962 NORESCO............................................. 13,441 5,126 (2,647) ---------- ---------- ---------- Total operating segments....................... 148,698 12,956 159,822 LESS: RECONCILING ITEMS Headquarters operating expenses (gains) not allocated to operating segments: Impairments of investments and other assets.... -- 19,756 8,655 Other.......................................... 3,080 2,331 (1,133) ---------- ---------- ---------- 145,618 (9,131) 152,300 Interest expense.................................... 37,132 40,302 34,903 Income tax expenses (benefit)....................... 39,356 (22,381) 43,210 ---------- ---------- ---------- Net income (loss) from continuing operations, before extraordinary item................... $ 69,130 $ (27,052) $ 74,187 ========== ========== ========== </TABLE> 53
54 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 T. FINANCIAL INFORMATION BY BUSINESS SEGMENT (CONTINUED) <TABLE> <CAPTION> YEARS ENDED DECEMBER 31, -------------------------------------- 1999 1998 1997 ---------- ---------- ---------- (THOUSANDS) <S> <C> <C> <C> OTHER SIGNIFICANT NONCASH EXPENSE ITEMS: Equitable Utilities: Increase (decrease) in deferred purchased natural gas cost....................................... $ (10,370) $ 4,608 $ 16,026 Noncash restructuring charges.................... -- 12,009 12,700 Equitable Production: Lease impairments................................ 3,518 36,908 -- Noncash restructuring charges.................... -- 6,812 2,200 NORESCO: Cost of contracts in excess of billings.......... 2,771 8,271 7,925 Noncash restructuring charges.................... -- 1,764 -- ---------- ---------- ---------- Total.......................................... $ (4,081) $ 70,372 $ 38,851 ========== ========== ========== SEGMENT ASSETS: Equitable Utilities................................. $ 914,630 $ 998,674 Equitable Production................................ 670,828 604,862 NORESCO............................................. 145,925 169,370 ---------- ---------- Total operating segments....................... 1,731,383 1,772,906 Headquarters assets, including cash and short-term investments and net intercompany accounts receivable....................................... 58,191 87,950 ---------- ---------- Total.......................................... $1,789,574 $1,860,856 ========== ========== EXPENDITURES FOR SEGMENT ASSETS (A): Equitable Utilities................................. $ 43,979 $ 20,860 Equitable Production................................ 92,099 126,752 NORESCO............................................. 6,041 11,102 ---------- ---------- Total.......................................... $ 142,119 $ 158,714 ========== ========== </TABLE> - --------------- (a) 1999 expenditures include $40 million for the acquisition of Carnegie Natural Gas Company, including $17.7 million in Equitable Utilities and $22.3 million in Equitable Production. See Note G. U. COMMITMENTS AND CONTINGENCIES There are various claims and legal proceedings against the Company arising from the normal course of business. Although counsel is unable to predict with certainty the ultimate outcome, management and counsel believe the Company has significant and meritorious defenses to any claims and intends to pursue them vigorously. Management believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company although they could be material to the reported results of operations for the period in which they occur. The Company has annual commitments of approximately $32.3 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 12 years at December 31, 1999, which relate to natural gas distribution operations. However, substantially all of these costs are recoverable in customer rates. 54
55 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 U. COMMITMENTS AND CONTINGENCIES (CONTINUED) The Company is subject to federal, state and local environmental 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 assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain of these 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. V. SUBSEQUENT EVENTS (UNAUDITED) In February 2000, the Company acquired the Appalachian production assets of Statoil Energy Inc. (Statoil) for $630 million, subject to customary closing adjustments. Statoil's operations consist of approximately 1.2 trillion cubic feet of proven natural gas reserves and 6,500 natural gas wells in West Virginia, Kentucky, Virginia, Pennsylvania and Ohio. Statoil's operations will be integrated into the Company's Production segment. No goodwill was recorded in connection with the acquisition, which was accounted for under the purchase method of accounting. In March 2000, the Company agreed to merge its Equitable Production - Gulf business with Westport, Inc., an oil and natural gas exploration and production company based in Denver, Colorado, for a 49% interest in the combined entity. The combined company intends to repay approximately $50 million of Equitable Production - Gulf intercompany debt and replace it with third party debt. 55
56 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 W. 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 oil and natural gas commodity prices: <TABLE> <CAPTION> MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- -------- ------------ ----------- (THOUSANDS EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> 1999 Operating revenues.......................... $420,053 $189,631 $191,605 $261,449 Operating income............................ 56,224 20,369 17,309 48,853 Net income from continuing operations before extraordinary items....................... 29,739 7,238 5,732 26,421 Earnings per share from continuing operations before extraordinary items: Basic.................................. $ 0.84 $ 0.21 $ 0.17 $ 0.80 Assuming dilution...................... $ 0.84 $ 0.21 $ 0.17 $ 0.79 1998 Operating revenues.......................... $283,449 $180,764 $157,971 $248,444 Operating income (loss)..................... 48,321 12,173 11,400 (83,692) Net income (loss) from continuing operations before extraordinary items................ 24,652 2,275 2,035 (56,014) Earnings (loss) per share from continuing operations before extraordinary items: Basic.................................. $ 0.66 $ 0.06 $ 0.06 $ (1.53) Assuming dilution...................... $ 0.66 $ 0.06 $ 0.06 $ (1.53) </TABLE> X. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Production segment in accordance with SFAS No. 69, "Disclosures About Oil and Natural Gas Producing Activities." The information presented for 1998 and 1999 excludes data associated with natural gas reserves related to rate-regulated and other utility operations. In 1999, the exploration and production operations conducted by Equitrans were transferred from Equitable Utilities to Equitable Production. Accordingly, the 1999 oil and natural gas information presented below reflects this transfer. These reserves (proved developed) are less than 5% of total Company proved reserves for the years presented. 56
57 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 X. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED) PRODUCTION COSTS The following table presents the costs incurred relating to natural gas and oil production activities: <TABLE> <CAPTION> 1999 1998 1997 -------- -------- -------- (THOUSANDS) <S> <C> <C> <C> At December 31: Capitalized costs................................ $947,803 $861,035 $779,936 Accumulated depreciation and depletion........... 410,921 355,535 293,594 -------- -------- -------- Net capitalized costs.............................. $536,882 $505,500 $486,342 ======== ======== ======== Costs incurred: Property acquisition: Proved properties............................. $ 23,165 $ 4,799 $ 68,334 Unproved properties........................... 722 18,069 15,813 Exploration........................................ 7,143 27,144 22,665 Development........................................ 59,647 76,762 40,982 </TABLE> RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES The following table presents the results of operations related to natural gas and oil production, including the effect in 1998 of impairment of assets as described in Note C: <TABLE> <CAPTION> 1999 1998 1997 -------- ------- ------- (THOUSANDS) <S> <C> <C> <C> Revenues: Affiliated....................................... $ 14,067 $39,553 $52,956 Nonaffiliated.................................... 158,369 99,437 97,493 Production costs................................... 26,206 30,390 31,777 Exploration expenses............................... 4,001 30,982 8,950 Depreciation and depletion......................... 52,009 49,348 41,153 Impairment of assets............................... 5,018 29,230 -- Income tax expense (benefit)....................... 32,911 (1,166) 26,303 -------- ------- ------- Results of operations from producing activities (excluding corporate overhead)................... $ 52,291 $ 206 $42,266 ======== ======= ======= </TABLE> RESERVE INFORMATION The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. In 1999, the Company decreased its estimate of the annual production decline from 4% to 3%, to be more representative of the region. This revision increased 1999 proved developed natural gas and crude oil reserves by 85,574 million cubic feet equivalent. Also during 1999, the exploration and production operations conducted by Equitrans were transferred to Equitable Production and reflected in the reserve information for 1999 as other additions to proved reserves of 43,829 million cubic feet equivalent. In 1997, the Company increased its Appalachian reserve life from 35 to 50 years to more closely reflect actual production experience. This revision increased 1997 proved developed natural gas and crude oil reserves by 78,607 million cubic feet equivalent. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. As of December 31, 1999 and 1998, 57
58 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 X. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED) all of the Company's proved reserves are in the United States. During 1997, the Company sold its Canadian properties, which accounted for less than 10% of the Company's proved reserves. <TABLE> <CAPTION> 1999 1998 1997 --------- ------- -------- (MILLIONS OF CUBIC FEET) <S> <C> <C> <C> NATURAL GAS Proved developed and undeveloped reserves: Beginning of year......................................... 899,881 889,828 849,530 Revision of previous estimates............................ 134,576 6,502 80,264 Purchase of natural gas in place.......................... 46,124 8,474 62,485 Sale of natural gas in place.............................. -- -- (107,138) Extensions, discoveries and other additions............... 132,180 54,970 61,380 Production................................................ (66,328) (59,893) (56,693) --------- ------- -------- End of year............................................... 1,146,433 899,881 889,828 ========= ======= ======== Proved developed reserves: Beginning of year......................................... 780,817 769,312 732,158 End of year............................................... 965,969 780,817 769,312 </TABLE> <TABLE> <CAPTION> 1999 1998 1997 ------ ------ ------- (THOUSANDS OF BARRELS) <S> <C> <C> <C> OIL Proved developed and undeveloped reserves: Beginning of year......................................... 9,826 10,100 19,517 Revision of previous estimates............................ (23) (966) 849 Purchase of oil in place.................................. 44 5 2,592 Sale of oil in place...................................... -- -- (12,392) Extensions, discoveries and other additions............... 1,155 1,661 1,045 Production................................................ (1,070) (974) (1,511) ------ ------ ------- End of year............................................... 9,932 9,826 10,100 ====== ====== ======= Proved developed reserves: Beginning of year......................................... 8,331 8,941 18,482 End of year............................................... 7,996 8,331 8,941 </TABLE> STANDARD MEASURE OF DISCOUNTED FUTURE CASH FLOW <TABLE> <CAPTION> 1999 1998 1997 ----------- ----------- ----------- (THOUSANDS) <S> <C> <C> <C> Future cash inflows.................................. $ 2,877,829 $1,870,002 $ 2,607,077 Future production costs.............................. (808,115) (606,777) (680,405) Future development costs............................. (139,626) (84,454) (80,965) ----------- ---------- ----------- Future net cash flow before income taxes............. 1,930,088 1,178,771 1,845,707 10% annual discount for estimated timing of cash flows.............................................. (1,098,185) (635,296) (1,027,826) ----------- ---------- ----------- Discounted future net cash flows before income taxes.............................................. 831,903 543,475 817,881 Future income tax expenses, discounted at 10% annually........................................... (251,467) (118,602) (276,887) ----------- ---------- ----------- Standardized measure of discounted future net cash flows.............................................. $ 580,436 $ 424,873 $ 540,994 =========== ========== =========== </TABLE> 58
59 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1999 X. NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED) 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: Summary of changes in the standardized measure of discounted future net cash flows: <TABLE> <CAPTION> 1999 1998 1997 --------- --------- --------- (THOUSANDS) <S> <C> <C> <C> Sales and transfers of natural gas and oil produced -- net........................................ $(146,230) $(108,600) $(118,672) Net changes in prices, production and development costs.................................................. 156,020 (343,061) (447,251) Extensions, discoveries, and improved recovery, less related costs.......................................... 140,402 67,986 58,205 Development costs incurred............................... 30,479 32,497 13,634 Purchase (sale) of minerals in place -- net.............. 26,152 6,439 (73,099) Revisions of previous quantity estimates................. 101,778 (260) 16,913 Accretion of discount.................................... 42,487 84,463 108,935 Net change in income taxes............................... (128,301) 158,285 143,429 Other.................................................... (67,224) (13,870) (45,814) --------- --------- --------- Net increase (decrease).................................. 155,563 (116,121) (343,720) Beginning of year........................................ 424,873 540,994 884,714 --------- --------- --------- End of year.............................................. $ 580,436 $ 424,873 $ 540,994 ========= ========= ========= </TABLE> ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable. 59
60 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required by Item 10 with respect to directors is incorporated herein by reference to the section describing "Election of Directors" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 17, 2000, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 1999. Information required by Item 10 with respect to compliance with Section 16(a) of the Exchange Act is incorporated by reference to the section describing "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 17, 2000. Information required by Item 10 with respect to executive officers is included herein after Item 4 at the end of Part I under the heading "Executive Officers of the Registrant." ITEM 11. EXECUTIVE COMPENSATION Information required by Item 11 is incorporated herein by reference to the sections describing "Executive Compensation," "Employment Contracts and Change-In-Control Arrangements" and "Pension Plan" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 17, 2000. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by Item 12 is incorporated herein by reference to the section describing "Voting Securities and Record Date" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 17, 2000. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. 60
61 PART IV ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K <TABLE> <C> <S> (a) 1. Financial Statements The financial statements listed in the accompanying index to financial statements are filed as part of this annual report. 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. 3. Exhibits The exhibits listed on the accompanying index to exhibits (pages 63 through 66) are filed as part of this annual report. </TABLE> (b) Reports on Form 8-K filed during the quarter ended December 31, 1999. None EQUITABLE RESOURCES, INC. INDEX TO FINANCIAL STATEMENTS COVERED BY REPORT OF INDEPENDENT AUDITORS (ITEM 14 (a)) <TABLE> <S> <C> 1. The following consolidated financial statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8: PAGE REFERENCE Statements of Consolidated Income for each of the three years in the period ended December 31, 1999 32 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1999 33 Consolidated Balance Sheets December 31, 1999 and 1998 34 - 35 Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 1999 36 Notes to Consolidated Financial Statements 37 - 59 2. Schedule for the Years Ended December 31, 1999, 1998 and 1997 included in Part IV: II -- Valuation and Qualifying Accounts and Reserves 62 </TABLE> 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. 61
62 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 1999 <TABLE> <CAPTION> COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E -------- ----------- ---------------------------- ---------- ---------- ADDITIONS BALANCE AT CHARGED BALANCE BEGINNING TO COSTS AT END DESCRIPTION OF PERIOD AND EXPENSES ACQUISITIONS DEDUCTIONS OF PERIOD ----------- ----------- ------------ ------------ ---------- ---------- <S> <C> <C> <C> <C> <C> 1999 Accumulated Provisions for Doubtful Accounts............ $ 9,818 $11,917 $108(b) $ (8,819)(a) $13,024 1998 Accumulated Provisions for Doubtful Accounts............ $10,284 $15,634 $ 21(c) $ 16,121 (a) $ 9,818 1997 Accumulated Provisions for Doubtful Accounts............ $10,930 $16,386 $243(d) $ 17,275 (a) $10,284 </TABLE> Note: (a) Customer accounts written off, less recoveries. (b) Addition to the Provision for Doubtful Accounts relates to the acquisition of Carnegie Distribution. (c) Addition to the Provision for Doubtful Accounts relates to the acquisition of LMI and Scallop. (d) Addition to the Provision for Doubtful Accounts relates to the acquisition of NORESCO. 62
63 INDEX TO EXHIBITS <TABLE> <CAPTION> EXHIBITS DESCRIPTION METHOD OF FILING -------- --------------------------------------- --------------------------------------- <S> <C> <C> 3.01 Restated Articles of Incorporation of Filed herewith as Exhibit 3.01 the Company dated May 18, 1999 3.02 Bylaws of the Company (amended through Filed as Exhibit 3.02 to Form 10-Q for April 28, 1999) the quarter ended March 31, 1999 4.01 (a) Indenture dated as of April 1, 1983 Filed as Exhibit 4.01 (Revised) to between the Company and Pittsburgh Post- Effective Amendment No. 1 to National Bank relating to Debt Registration Statement (Registration Securities No. 2-80575) 4.01 (b) Instrument appointing Bankers Trust Filed as Exhibit 4.01 (b) to Form 10-K Company as successor trustee to for the year ended December 31, 1998 Pittsburgh National Bank 4.01 (c) Resolutions adopted June 22, 1987 by Filed as Exhibit 4.01 (c) to Form 10-K the Finance Committee of the Board of for the year ended December 31, 1998 Directors of the Company establishing the terms of the 75,000 units (debentures with warrants) issued July 1, 1987 4.01 (d) Supplemental indenture dated March 15, Filed as Exhibit 4.01 (f) to Form 10-K 1991 with Bankers Trust Company for the year ended December 31, 1996 eliminating limitations on liens and additional funded debt 4.01 (e) Resolution adopted August 19, 1991 by Filed as Exhibit 4.01 (g) to Form 10-K the Ad Hoc Finance Committee of the for the year ended December 31, 1996 Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes 4.01 (f) Resolutions adopted July 6, 1992 and Refiled as Exhibit 4.01 (h) to Form February 19, 1993 by the Ad Hoc Finance 10-K for the year ended December 31, Committee of the Board of Directors of 1997 the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes 4.01 (g) Resolution adopted July 14, 1994 by the Filed as Exhibit 4.01 (i) to Form 10-K Ad Hoc Finance Committee of the Board for the year ended December 31, 1995 of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes 4.01 (h) Resolution adopted January 18 and July Filed as Exhibit 4.01(j) to Form 10-K 18, 1996 by the Board of Directors of for the year ended December 31, 1996 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 </TABLE> Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*). 63
64 INDEX TO EXHIBITS <TABLE> <CAPTION> EXHIBITS DESCRIPTION METHOD OF FILING -------- --------------------------------------- --------------------------------------- <S> <C> <C> 4.01 (i) Junior Subordinated Indenture Between Filed as Exhibit 4.1 to Form 10-Q for Equitable Resources, Inc. and Bankers the quarter ended June 30, 1998 Trust Company 4.01 (j) Amended and Restated Trust Agreement Filed as Exhibit 4.2 to Form 10-Q for Between Equitable Resources, Inc. and the quarter ended June 30, 1998 Bankers Trust Company 4.01 (k) Equitable Resources, Inc. 7.35% Junior Filed as Exhibit 4.3 to Form 10-Q for Subordinated Deferrable Interest the quarter ended June 30, 1998 Debentures Certificate 4.01 (l) Rights Agreement dated as of April 1, Filed as Exhibit 1 to Registration 1996 between the Company and Chemical Statement on Form 8-A filed April 16, Mellon Shareholder Services, L.L.C., 1996 setting forth the terms of the Company's Preferred Stock Purchase Rights Plan 10.01 Trust Agreement with Pittsburgh Refiled herewith as Exhibit 10.01 to National Bank to act as Trustee for Form 10-K pursuant to Item 10 (d) of Supplemental Pension Plan, Supplemental Regulation S-K Deferred Compensation Benefits, Retirement Program for Board of Directors and Supplemental Executive Retirement Plan * 10.02 Equitable Resources, Inc. Directors' Filed as Exhibit 10.4 to Form 10-Q for Deferred Compensation Plan the quarter ended September 30, 1999 * 10.03 1999 Equitable Resources, Inc. Filed as Exhibit 10.2 to Form 10-Q for Long-Term Incentive Plan (as amended the quarter ended June 30, 1999 May 26, 1999) * 10.04 1999 Equitable Resources, Inc. Filed herewith as Exhibit 10.04 Short-Term Incentive Plan * 10.05 1999 Equitable Resources, Inc. Non- Filed as Exhibit 10.1 to Form 10-Q for Employee Directors' Stock Incentive the quarter ended June 30, 1999 Plan (as amended May 26, 1999) * 10.06 Equitable Resources, Inc. 1994 Refiled herewith as Exhibit 10.06 Long-Term Incentive Plan pursuant to Item 10 (d) of Regulation S-K * 10.07 Equitable Resources, Inc. Deferred Filed herewith as Exhibit 10.07 Compensation Plan (Amended and Restated Effective October 27, 1999) * 10.08 Equitable Resources, Inc. Breakthrough Filed herewith as Exhibit 10.08 Long-Term Incentive Plan with certain executives of the Company (as amended through November 30, 1999) * 10.09 (a) Employment Agreement dated as of May 4, Filed as Exhibit 10.2 to Form 10-Q for 1998 with Murry S. Gerber the quarter ended June 30, 1998 * 10.09 (b) Amendment No. 1 to Employment Agreement Filed herewith as Exhibit 10.09 (b) with Murry S. Gerber </TABLE> Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*). 64
65 INDEX TO EXHIBITS <TABLE> <CAPTION> EXHIBITS DESCRIPTION METHOD OF FILING -------- --------------------------------------- --------------------------------------- <S> <C> <C> * 10.10 Change in Control Agreement dated Filed herewith as Exhibit 10.10 December 1, 1999 with Murry S. Gerber * 10.11 Supplemental Executive Retirement Filed as Exhibit 10.4 to Form 10-Q for Agreement dated as of May 4, 1998 with the quarter ended June 30, 1998 Murry S. Gerber * 10.12 Amended and Restated Post-Termination Filed herewith as Exhibit 10.12 Confidentiality and Non-Competition Agreement dated December 1, 1999 with Murry S. Gerber * 10.13 (a) Employment Agreement dated as of July Filed as Exhibit 10.1 to Form 10-Q for 1, 1998 with David L. Porges the quarter ended September 30, 1998 * 10.13 (b) Amendment No. 1 to Employment Agreement Filed herewith as Exhibit 10.13 (b) with David L. Porges * 10.14 Change of Control Agreement dated Filed herewith as Exhibit 10.14 December 1, 1999 with David L. Porges * 10.15 Amended and Restated Post-Termination Filed herewith as Exhibit 10.15 Confidentiality and Non-Competition Agreement dated December 1, 1999 with David L. Porges * 10.16 Change of Control Agreement dated Filed herewith as Exhibit 10.16 December 1, 1999 with Gregory R. Spencer * 10.17 Non-compete Agreement dated December 1, Filed herewith as Exhibit 10.17 1999 with Gregory R. Spencer * 10.18 Change of Control Agreement dated Filed herewith as Exhibit 10.18 December 1, 1999 with Johanna G. O'Loughlin * 10.19 Non-compete Agreement dated December 1, Filed herewith as Exhibit 10.19 1999 with Johanna G. O'Loughlin * 10.20 (a) Agreement dated May 29, 1996 with Paul Filed as Exhibit 10.04 (a) to Form 10-K Christiano for deferred payment of 1996 for the year ended December 31, 1996 director fees beginning May 29, 1996 * 10.20 (b) Agreement dated November 26, 1996 with Filed as Exhibit 10.04 (b) to Form 10-K Paul Christiano for deferred payment of for the year ended December 31, 1996 1997 director fees * 10.20 (c) Agreement dated December 1, 1997 with Filed as Exhibit 10.04 (c) to Form 10-K Paul Christiano for deferred payment of for the year ended December 31, 1997 1998 director fees * 10.20 (d) Agreement dated December 15, 1998 with Filed as Exhibit 10.19 (d) to Form 10-K Paul Christiano for deferred payment of for the year ended December 31, 1998 1999 director fees * 10.20 (e) Agreement dated November 29, 1999 with Filed herewith as Exhibit 10.20 (e) Paul Christiano for deferred payment of 2000 director fees </TABLE> Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*). 65
66 INDEX TO EXHIBITS <TABLE> <CAPTION> EXHIBITS DESCRIPTION METHOD OF FILING -------- --------------------------------------- --------------------------------------- <S> <C> <C> * 10.21 (a) Agreement dated May 24, 1996 with Filed as Exhibit 10.14 (a) to Form 10-K Phyllis A. Domm for deferred payment of for the year ended December 31, 1996 1996 director fees beginning May 24, 1996 * 10.21 (b) Agreement dated November 27, 1996 with Filed as Exhibit 10.14 (b) to Form 10-K Phyllis A. Domm for deferred payment of for the year ended December 31, 1996 1997 director fees * 10.21 (c) Agreement dated November 30, 1997 with Filed as Exhibit 10.14 (c) to Form 10-K Phyllis A. Domm for deferred payment of for the year ended December 31, 1997 1998 director fees * 10.21 (d) Agreement dated December 5, 1998 with Filed as Exhibit 10.20 (d) to Form 10-K Phyllis A. Domm for deferred payment of for the year ended December 31, 1998 1999 director fees * 10.21 (e) Agreement dated November 30, 1999 with Filed herewith as Exhibit 10.21 (e) Phyllis A. Domm for deferred payment of 2000 director fees * 10.22 (a) Agreement dated December 31, 1987 with Filed as Exhibit 10.21 (a) to Form 10-K Malcolm M. Prine for deferred payment for the year ended December 31, 1998 of 1988 director fees * 10.22 (b) Agreement dated December 30, 1988 with Filed as Exhibit 10.21 (b) to Form 10-K Malcolm M. Prine for deferred payment for the year ended December 31, 1998 of 1989 director fees * 10.23 Release Agreement dated December 8, Filed herewith as Exhibit 10.23 1999 with John C. Gongas, Jr. 10.24 Purchase Agreement by and among Filed as Exhibit 10.5 to Form 10-Q for Equitable Resources Energy Company, ET the quarter ended September 30, 1998 Bluegrass Company, EREC Nevada, Inc. and ERI Services, Inc. and AEP Resources, Inc. dated September 12, 1998 for the purchase of midstream assets 21 Schedule of Subsidiaries Filed herewith as Exhibit 21 23.01 Consent of Independent Auditors Filed herewith as Exhibit 23.01 27.01 (a) Financial Data Schedule for Year 1999 Filed electronically 27.01 (b) Restated Financial Data Schedule for Filed electronically Year 1998 27.01 (c) Restated Financial Data Schedule for Filed electronically Year 1997 </TABLE> - --------------- 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 (*). 66
67 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. EQUITABLE RESOURCES, INC. By: /s/ MURRY S. GERBER ------------------------------------- Murry S. Gerber President and Chief Executive Officer Pursuant to the requirements of the Securities and 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. <TABLE> <S> <C> <C> /s/ MURRY S. GERBER President and Chief Executive Officer March 15, 2000 - ------------------------------------- and Director Murry S. Gerber (Principal Executive Officer) /s/ DAVID L. PORGES Executive Vice President and March 15, 2000 - ------------------------------------- Chief Financial Officer David L. Porges (Principal Financial Officer) /s/ JOHN A. BERGONZI Corporate Controller and March 15, 2000 - ------------------------------------- Assistant Treasurer John A. Bergonzi (Principal Accounting Officer) /s/ PAUL CHRISTIANO Director March 15, 2000 - ------------------------------------- Paul Christiano /s/ PHYLLIS A. DOMM Director March 15, 2000 - ------------------------------------- Phyllis A. Domm /s/ E. LAWRENCE KEYES, JR. Director March 15, 2000 - ------------------------------------- E. Lawrence Keyes, Jr. /s/ THOMAS A. MCCONOMY Director March 15, 2000 - ------------------------------------- Thomas A. McConomy /s/ DONALD I. MORITZ Director March 15, 2000 - ------------------------------------- Donald I. Moritz /s/ GUY W. NICHOLS Director March 15, 2000 - ------------------------------------- Guy W. Nichols /s/ MALCOLM M. PRINE Director March 15, 2000 - ------------------------------------- Malcolm M. Prine /s/ JAMES E. ROHR Director March 15, 2000 - ------------------------------------- James E. Rohr /s/ DAVID S. SHAPIRA Director March 15, 2000 - ------------------------------------- David S. Shapira /s/ J. MICHAEL TALBERT Director March 15, 2000 - ------------------------------------- J. Michael Talbert </TABLE> 67