-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QnW3tlAUT2kMcZVIeX71KVHC42pjdbYc8Cq4+AgD6yA2iZ6wnPanp6/o4pN6Kxo3 fBE/dGbWafJFChi26n3Jcw== 0000950134-96-005105.txt : 19961001 0000950134-96-005105.hdr.sgml : 19961001 ACCESSION NUMBER: 0000950134-96-005105 CONFORMED SUBMISSION TYPE: 8-K/A PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960721 ITEM INFORMATION: Acquisition or disposition of assets ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 19960930 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NOBLE AFFILIATES INC CENTRAL INDEX KEY: 0000072207 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 730785597 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-07964 FILM NUMBER: 96636490 BUSINESS ADDRESS: STREET 1: 110 W BROADWAY STREET 2: P O BOX 1967 CITY: ARDMORE STATE: OK ZIP: 73402-1967 BUSINESS PHONE: 4052234110 MAIL ADDRESS: STREET 1: P O BOX 1967 STREET 2: 110 WEST BROADWAY CITY: ARDMORE STATE: OK ZIP: 73402-1967 8-K/A 1 AMENDMENT TO FORM 8-K 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K/A (NO. 1) CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): JULY 31, 1996 NOBLE AFFILIATES, INC. (Exact name of registrant as specified in its charter) DELAWARE 0-7062 73-0785597 (State or other (Commission (IRS Employer jurisdiction of File Number) Identification No.) incorporation) 110 WEST BROADWAY ARDMORE, OKLAHOMA 73401 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (405) 223-4110 2 NOBLE AFFILIATES, INC. FORM 8-K/A (NO.1) On July 31, 1996, Samedan Oil Corporation ("Samedan"), a wholly owned subsidiary of the Registrant, purchased all of the outstanding common stock of Energy Development Corporation, a wholly owned indirect subsidiary of Public Service Enterprise Group Incorporated (the "EDC Acquisition"). The EDC Acquisition was reported by the Registrant in its Form 8-K (Date of Event: July 31, 1996) dated August 13, 1996, in accordance with the rules and regulations of the Securities and Exchange Commission (the "Commission"). Pursuant to Items 7(a)(4) and 7(b)(2) of Form 8-K, this Form 8-K/A (No. 1) is being filed to amend the Registrant's Form 8-K to include the financial statements and pro forma financial information required by Item 7 of Form 8-K. In addition, the Registrant has included certain information as of July 31, 1996, the date of the EDC Acquisition, unless otherwise specified, describing the principal business and properties of EDC. As used herein, the "Company" refers to Noble Affiliates, Inc. and its subsidiaries (including EDC), and "EDC" refers to Energy Development Corporation and its subsidiaries. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Form 8-K/A (No. 1) includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Form 8-K/A (No. 1), including without limitation, statements regarding the Registrant's estimates of oil and gas reserves and future net cash flows attributable thereto, anticipated capital expenditures, business strategy, plans and objectives of management of the Registrant for future operations and industry conditions, are forward-looking statements. Although the Registrant believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Registrant's expectations ("Cautionary Statements") include, without limitation, future production levels, future prices and demand for oil and gas, results of future exploration and development activities, future operating and development costs, the effect of existing and future laws and governmental regulations (including those pertaining to the environment), and the political and economic climate of the United States and the foreign countries in which the Registrant operates from time to time, as discussed elsewhere in this Form 8-K/A (No. 1) and the other documents of the Registrant filed with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the Registrant or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. 2 3 Item 2. Acquisitions or Dispositions. ENERGY DEVELOPMENT CORPORATION EDC is an independent energy company which has been principally engaged in the exploration for and production of crude oil and natural gas since 1972. EDC's properties are located throughout the major oil and gas producing basins of the United States, principally in the Gulf of Mexico and onshore gulf coast of Louisiana and Texas, and internationally in Argentina and the United Kingdom sector of the North Sea. Quantities of oil, condensate and natural gas liquids are expressed in this Report in barrels ("bbls"), thousands of barrels ("Mbbls") or millions of barrels ("MMbbls"), and quantities of natural gas are expressed in thousands of cubic feet ("Mcf"), millions of cubic feet ("MMcf") or billions of cubic feet ("Bcf"). As used herein, "Mcfe" means thousands of cubic feet of gas equivalent, "MMcfe" means millions of cubic feet of gas equivalent and "Bcfe" means billions of cubic feet of gas equivalent; and MMBTU's means millions of British Thermal Units. Oil, condensate and natural gas liquids are converted to gas equivalents using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. OIL AND GAS RESERVES The following table sets forth information as to the estimated net proved and proved developed reserves for EDC as of July 31, 1996, as prepared by Samedan. TOTAL PROVED AND PROVED DEVELOPED RESERVES AS OF JULY 31, 1996
GAS (BCF) OIL (MMBBLS) ------------------------- -------------------- Total Proved Reserves: Domestic: Offshore Gulf of Mexico . . . . . . . . . . 221.5 12.0 Onshore . . . . . . . . . . . . . . . . . . 150.5 4.0 ---------- ---------- 372.0 16.0 International . . . . . . . . . . . . . . . . . . 45.3 19.7 ---------- --------- 417.3 35.7 ========== ========= Total Proved Developed Reserves . . . . . . . . . . . . 363.4 27.5 ========== =========
In connection with the EDC Acquisition, Samedan's in-house engineers prepared the reserve estimates set forth above. Prior to the closing of the EDC Acquisition, Miller and Lents, Ltd., independent petroleum consultants ("Miller and Lents"), estimated EDC's proved reserves as of July 1, 1996. The Miller and Lents reserve estimates are summarized below under "--Miller and Lents Reserve Report." After taking into account adjustments for EDC's production and exploration and development activities during July 1996, there are no material differences in the aggregate between such estimate of proved reserves prepared by Miller and Lents and the estimate of proved reserves prepared by Samedan as summarized above. With respect to the domestic offshore Gulf of Mexico proved reserves, Samedan's estimate is higher than that of Miller and Lents due principally to Samedan's consideration of recent discoveries reflected in its estimate as of July 31, 1996 (as compared to Miller and Lents' estimate as of July 1, 1996) and of information available to Samedan as the operator of certain properties in which it acquired additional interests in the EDC Acquisition. With respect to the domestic onshore proved reserves, Samedan's estimate is lower than that of Miller and Lents due principally to Samedan's estimation of higher abandonment costs associated primarily with the South Lake Arthur (South Louisiana) properties and its consideration of recent operating performance reflected in its estimate as of July 31, 1996 (as compared to Miller and Lents' estimate as of July 1, 1996). Because of the direct relationship between quantities of proved undeveloped reserves and development plans, Samedan has assigned to undeveloped locations only those reserves that will definitely be drilled, and only those reserves assigned to the undeveloped portions of secondary or tertiary projects that will definitely be developed have been included in proved reserves as proved undeveloped reserves. EDC has interests in certain tracts that may have additional hydrocarbon quantities that were not classified at the time of the estimate as proved reserves because Samedan did not have definitive plans at such time to drill or develop these tracts, but which tracts may be reclassified as proved reserves in the future as a result of EDC's exploration and development programs. Under 3 4 the regulations of the Commission, a company may classify reserves as proved undeveloped reserves, assuming they otherwise meet the Commission's criteria for proved reserves, without regard to whether such company has definitive plans to drill or develop such reserves. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured, and estimates of other engineers might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. In addition, estimates of EDC's proved reserves are based on oil and gas prices and production and development costs prevailing at the date of the estimate. Any significant variance in future prices or costs could materially affect the estimated quantities of reserves set forth in this Report. MILLER AND LENTS RESERVE REPORT The following table sets forth information as to estimated net proved and proved developed reserves for EDC as of July 1, 1996, as prepared by Miller and Lents. TOTAL PROVED AND PROVED DEVELOPED RESERVES AS OF JULY 1, 1996
GAS (BCF) OIL (MMBBLS) ------------------------- --------------------- Total Proved Reserves: Domestic: Offshore Gulf of Mexico . . . . . . . . . . 182.1 8.2 Onshore . . . . . . . . . . . . . . . . . . 201.3 7.3 ---------- ----------- 383.4 15.5 International . . . . . . . . . . . . . . . . . . 40.6 24.9 ---------- ---------- 424.0 40.5 ========== ========== Total Proved Developed Reserves . . . . . . . . . . . . 347.6 28.8 ========== ==========
In the Miller and Lents reserve report, proved undeveloped reserves were assigned to the undrilled locations that satisfied the following conditions: (i) the location was a direct offset to wells that have indicated commercial production in the objective formation, (ii) it is reasonably certain that the location was within the known proved productive limits of the objective formation, (iii) the location conformed to existing well spacing regulations, if any, and (iv) it was reasonably certain that the location would be developed. Reserves for other undrilled locations were classified as proved undeveloped only in those cases where interpretations of data from wells indicated that the objective formation is laterally continuous and contains commercially recoverable hydrocarbons at locations beyond direct offset locations. Miller and Lents has delivered to EDC a summary reserve report describing Miller and Lents' review process and conclusions, a copy of which has been filed as an exhibit to this Form 8-K/A (No. 1). PRIMARY OPERATING AREAS Offshore Gulf of Mexico. EDC owns economic interests in leases covering 189 blocks in federal and state waters offshore Texas and Louisiana. The majority of these interests lie in the shallower waters of the Gulf of Mexico. Gulf of Mexico fields typically exhibit high initial production rates. EDC's proved reserves in this region are estimated by Samedan, as of July 31, 1996, to be 294 Bcfe, or approximately 46 percent of EDC's total proved reserves. EDC owns an interest in 121 platforms in these waters, 26 of which are operated by EDC and six of which are operated by Samedan. Significant producing properties in the Gulf of Mexico include Burrwood (South 4 5 Pass), Vermilion block 370, Ship Shoal block 113, Eugene Island block 57, Mississippi Canyon block 661/705 and Vermilion block 100. EDC owns working interests ranging from 19 to 100 percent in the aforementioned properties and operates Vermilion block 100. The acquisition of EDC's 21 percent interest in Vermilion block 370, which is operated by Samedan, increases the Company's working interest to 58 percent. Net daily production attributable to EDC's producing platforms averaged 97 MMcf of gas and 4,300 bbls of oil for the first six months of 1996, or approximately 44 percent of EDC's total average daily production for such period. Domestic Onshore. EDC owns 410 properties, including 140 producing fields, in the coastal regions of Texas and Louisiana, the Permian Basin of West Texas and other areas in Texas and Louisiana. EDC's proved reserves in this region are estimated by Samedan, as of July 31, 1996, to be 125 Bcfe, or approximately 20 percent of EDC's total proved reserves. Approximately 43 percent of the proved reserves in this region are attributable to seven properties: South Lake Arthur (South Louisiana), Loma Vieja (West Texas), Caspiana (Northwest Louisiana), Maurice (South Louisiana), Maurice North (South Louisiana), McAllen Ranch (South Texas) and Gomez (West Texas). EDC owns working interests in such properties ranging from 10 to 100 percent and acts as operator for five of these properties. EDC owns 305 properties, including 14 producing fields, in Kansas and Oklahoma. These fields typically have long lived reserves. EDC's proved reserves in this region are estimated by Samedan, as of July 31, 1996, to be 50 Bcfe, or approximately eight percent of EDC's total proved reserves. Approximately 98 percent of the proved reserves in this region are attributable to two properties, Guymon-Hugoton and Panoma. EDC has an average 35 percent working interest in 146 wells in the Guymon-Hugoton field, which is located in the largest gas field in North America. The Panoma Gas Area is operated by EDC, with a working interest of 52 percent. Net daily production attributable to the domestic onshore producing properties averaged 100 MMcf of gas and 2,900 bbls of oil for the first six months of 1996, or approximately 42 percent of EDC's total average daily production for such period. International. EDC's international reserves are located in Argentina and the United Kingdom. EDC's international proved reserves are estimated by Samedan, as of July 31, 1996, to be 163 Bcfe, or approximately 26 percent of EDC's total proved reserves. In Argentina, the Company owns a 14 percent working interest in the El Tordillo field, located in the San Jorge Basin of the Chubut Province, approximately 1,000 miles south of Buenos Aires. The Company holds an interest in 11 offshore production platforms in the United Kingdom sector of the North Sea and four producing fields onshore in southern England. The Company does not operate any of its United Kingdom or Argentinean properties. Net daily production attributable to Argentina and the United Kingdom averaged 9 MMcf of gas and 4,600 bbls of oil for the first six months of 1996, or approximately 14 percent of EDC's total average daily production for such period. 5 6 ACREAGE DATA The following table sets forth developed and undeveloped leasehold acreage (including both leases and concessions) held by EDC as of December 31, 1995. DEVELOPED AND UNDEVELOPED LEASEHOLD ACREAGE AS OF DECEMBER 31, 1995
DEVELOPED ACRES(1) UNDEVELOPED ACRES(2) ------------------------------------- ----------------------------- LOCATION GROSS(3) NET(4) GROSS(3) NET(4) -------- ----------------- ----------------- ----------------- ---------- Domestic: Offshore Gulf of Mexico . . . 335,488 111,338 222,890 125,245 Onshore . . . . . . . . . . . 392,314 136,301 710,544 358,099 ----------- ----------- ----------- ----------- 727,802 247,639 933,434 483,344 International . . . . . . . . . . 162,820 10,826 7,325,956(5) 4,824,247(5) ----------- ------------ ----------- ----------- 890,622 258,465 8,259,390(5) 5,307,591(5) =========== =========== =========== ===========
- ----------------- (1) Developed acreage is acreage spaced or assignable to productive wells. (2) Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those lease acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well so holding such lease. (3) A gross acre is an acre in which working interest is owned. (4) A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. (5) Includes a significant number of acres which to date have not been thoroughly evaluated by Samedan subsequent to the EDC Acquisition. The Company anticipates that the reported acreage may be subject to reduction upon the conclusion of its evaluations. As of December 31, 1995, EDC held royalty, overriding royalty and other mineral interests in 37,663 net acres in addition to the developed and undeveloped leasehold acreage indicated above. EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the number of gross and net exploratory and development wells drilled by or on behalf of EDC for the periods indicated. An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the following table and as defined in the rules and regulations of the Commission, is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated; and "completion" refers to the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency. 6 7
EXPLORATORY WELLS ------------------------------------------------------------------------------- PRODUCTIVE(1) DRY(2) --------------------------------------- -------------------------------------- DOMESTIC INTERNATIONAL DOMESTIC INTERNATIONAL YEAR ENDED ------------------ ------------------ ------------------ ------------------ DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET ----------- -------- -------- ------- -------- -------- -------- -------- ------- 1993 . . . . . . . . . . . . . 5 2.41 -- -- 7 3.51 -- -- 1994 . . . . . . . . . . . . . 6 3.84 -- -- 12 4.99 2 .62 1995 . . . . . . . . . . . . . 11 4.27 -- -- 9 6.29 2 .13
DEVELOPMENT WELLS ------------------------------------------------------------------------------- PRODUCTIVE(1) DRY(2) --------------------------------------- -------------------------------------- DOMESTIC INTERNATIONAL DOMESTIC INTERNATIONAL YEAR ENDED ------------------ ------------------ ------------------ ------------------ DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET ----------- -------- -------- ------- -------- -------- -------- -------- ------- 1993 . . . . . . . . . . . . . 35 9.68 5 .34 4 2.25 -- -- 1994 . . . . . . . . . . . . . 46 11.41 13 1.04 5 1.93 1 .11 1995 . . . . . . . . . . . . . 34 10.37 14 1.69 4 1.69 -- --
- ----------------- (1) A productive well is an exploratory or a development well that is not a dry hole. (2) A dry hole is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. EDC does not own any drilling rigs and all of its drilling activities are conducted by independent contractors under standard drilling contracts. PRODUCTIVE WELLS The following table sets forth the number of productive oil and gas wells in which EDC had interests as of December 31, 1995.
PRODUCTIVE WELLS(1)(2) ------------------------------------------------------------------ OIL GAS ---------------------------------- ------------------------------ LOCATION GROSS(3) NET(4) GROSS(3) NET(4) -------- ---------------- ---------------- ---------------- ----------- Domestic: Offshore Gulf of Mexico . . . . . . 148 86 482 150 Onshore . . . . . . . . . . . . . . 3,469 184 570 222 ------- -------- --------- --------- 3,617 270 1,052 372 International . . . . . . . . . . . . . 502 45 30 2 -------- --------- --------- ---------- 4,119 315 1,082 374 ======== ========= ======== =========
- ----------------- (1) Productive wells are producing wells and wells capable of production. (2) One or more completions in the same bore hole is counted as one well. Included in the table and counted as one gross well each are 12 gross oil wells (5 net) and 52 gross gas wells (22 net) that are multiple completions. Also included in the table are 1,464 gross oil wells (126 net) and 392 gross gas wells (125 net) that were not producing at December 31, 1995 because such wells were awaiting additional action or pipeline connections. 7 8 (3) A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. (4) A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. VOLUME, PRICES AND PRODUCTION COSTS The following table sets forth for the periods indicated certain information regarding EDC's average daily production volumes, average sales prices (including transfers) per unit produced and average production (lifting) cost per unit of production.
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED -------------------------------------------- JUNE 30, 1993 1994 1995 1996 -------------- ------------- ------------ -------------- Average daily production: Natural gas (MMcf) . . . . . . . . . . . 262 228 205 205 Oil and condensate (Mbbls) . . . . . . . 10 11 11 12 Gas equivalent (MMcfe) . . . . . . . . . 325 295 271 276 Average sales price: Natural gas (per Mcf)(1) . . . . . . . . $ 2.20 $ 1.98 $ 1.78 $ 2.19 Oil and condensate (per bbl)(2) . . . . $ 16.23 $ 15.03 $ 16.61 $ 16.06 Average production (lifting) cost per unit of oil and natural gas production, excluding depreciation (per Mcfe) . . $ .44 $ .50 $ .49 $ .50
- ----------------- (1) Includes the effect of hedging transactions. The amounts shown reflect an increase of $.05 per Mcf for 1993, an increase of $.05 per Mcf for 1995 and a decrease of $.36 per Mcf for the six months ended June 30, 1996, due to hedging transactions. (2) Includes the effect of hedging transactions. The amounts shown reflect an increase of $.04 per bbl for 1994, an increase of $.28 per bbl for 1995 and a decrease of $2.52 per bbl for the six months ended June 30, 1996, due to hedging transactions. HEDGING ARRANGEMENTS EDC had natural gas futures contracts which were sold and closed at July 31, 1996 that hedged, at an average price of $1.89 per MMBTU, 513 million MMBTU of gas for the period August 1996 through December 1996, or approximately 16 percent of EDC's expected gas production for such period. The net realized deferred loss on these contracts at July 31, 1996 amounted to approximately $1.45 million. EDC had crude oil futures contracts open and outstanding at July 31, 1996 that hedged, at an average price of $19.45 per bbl, 1,775,000 bbls of oil for the period August 1996 through December 1996, or approximately 97 percent of EDC's expected oil production for such period. The net unrealized deferred loss on these contracts at July 31, 1996 amounted to approximately $1.59 million. The losses on these contracts actually realized, if any, are expected to be offset by the higher cash proceeds received from the hedged item when produced and sold. All future contracts outstanding at July 31, 1996 were New York Mercantile Exchange trade contracts. EDC also has crude oil collar hedges for the period August 1996 through December 1996 for a total of 1,355,000 bbls of oil with a floor price of $18.00 and a ceiling price of $20.015 per bbl. 8 9 SEISMIC DATA At July 31, 1996, EDC owned or held licenses covering 8,100 square miles of 3-D seismic data and 252,000 linear miles of 2-D seismic data. Certain of such licenses contain "change of control" provisions that will require additional payments by the Company for the continued use of such seismic data as a result of the EDC Acquisition. EDC owns a proprietary interest in and will retain ownership of its rights to use approximately 10 percent of the 3-D seismic data and one percent of the 2-D seismic data. OTHER ACTIVITIES Ecuador Agreement. In July 1996, EDC entered into an agreement with Petroecuador which grants EDC the exploration, production and commercial rights with respect to approximately 864,000 gross acres in Block 3 offshore Ecuador. Under this agreement, EDC is obligated to complete an exploration program by July 2000, consisting of a 3-D seismic program and the drilling of four wells, at an estimated aggregate cost of $45 million. The Company may seek to reduce its interest under this agreement by obtaining one or more partners for this prospect. MANAGEMENT AND EMPLOYEES Upon the closing of the EDC Acquisition, the directors and officers of Samedan assumed similar positions as directors and officers of EDC. At June 30, 1996, EDC had approximately 220 employees, 62 of whom were terminated upon the closing of the EDC Acquisition. The remaining employees of EDC will be terminated on October 31, 1996. Samedan expects to hire approximately 90 additional employees as a result of the EDC Acquisition, including certain former employees of EDC. OTHER MATTERS EDC is subject to the various competitive conditions, regulatory requirements (including regulations pertaining to the environment) and operating risks and hazards experienced by other independent energy companies. Reference is made to the Company's Form 10-K for the year ended December 31, 1995 for a discussion of such matters. 9 10 Item 7. Financial Statements and Exhibits. (a) Financial Statements of Business Acquired. Audited Consolidated Financial Statements of Energy Development Corporation filed as part of this report: - Report of Deloitte & Touche LLP, Independent Auditors - Consolidated Statements of Income for the years ended December 31, 1993, 1994 and 1995 - Consolidated Balance Sheets as of December 31, 1994 and 1995 - Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1994 and 1995 - Consolidated Statements of Changes in Stockholder's Equity for the years ended December 31, 1993, 1994 and 1995 - Notes to Consolidated Financial Statements Unaudited Consolidated Condensed Financial Statements of Energy Development Corporation filed as part of this report: - Consolidated Condensed Statements of Income for the six months ended June 30, 1995 and 1996 - Consolidated Condensed Balance Sheet as of June 30, 1996 - Consolidated Condensed Statements of Cash Flows for the six months ended June 30, 1995 and 1996 - Notes to Consolidated Condensed Financial Statements (b) Pro Forma Financial Information. Unaudited Pro Forma Consolidated Condensed Financial Statements of Noble Affiliates, Inc. and subsidiaries filed as a part of this report: - Pro Forma Consolidated Condensed Statement of Operations for the six months ended June 30, 1996 and the year ended December 31, 1995 - Notes to the Pro Forma Consolidated Condensed Statement of Operations - Pro Forma Consolidated Condensed Balance Sheet as of June 30, 1996 - Notes to the Pro Forma Consolidated Condensed Balance Sheet (c) Exhibits. 23.1 - Consent of Miller and Lents, Ltd. 23.2 - Consent of Deloitte & Touche LLP 99.1 - Summary Reserve Report on the estimated reserves of EDC as of July 1, 1996, prepared by Miller and Lents, Ltd., independent petroleum consultants 10 11 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Date: September 27, 1996 NOBLE AFFILIATES, INC. By: /s/ WILLIAM D. DICKSON ------------------------------- William D. Dickson, Vice President - Finance and Treasurer 11 12 INDEX TO FINANCIAL STATEMENTS
PAGE ---- ENERGY DEVELOPMENT CORPORATION: Consolidated Financial Statements (Audited): Report of Deloitte & Touche LLP, Independent Auditors . . . . . . . . . . . . . . . F-2 Consolidated Statements of Income for the years ended December 31, 1993, 1994 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3 Consolidated Balance Sheets as of December 31, 1994 and 1995 . . . . . . . . . . . . F-4 Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1994 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5 Consolidated Statements of Changes in Stockholder's Equity for the years ended December 31, 1993, 1994 and 1995 . . . . . . . . . . . . . . . . . . . . . . F-6 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . F-7 Consolidated Condensed Financial Statements (Unaudited): Consolidated Condensed Statements of Income for the six months ended June 30, 1995 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-24 Consolidated Condensed Balance Sheet as of June 30, 1996 . . . . . . . . . . . . . . F-25 Consolidated Condensed Statements of Cash Flows for the six months ended June 30, 1995 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . F-26 Notes to Consolidated Condensed Financial Statements . . . . . . . . . . . . . . . . F-27 NOBLE AFFILIATES, INC. AND SUBSIDIARIES: Pro Forma Consolidated Condensed Financial Statements (Unaudited): Pro Forma Consolidated Condensed Statement of Operations for the six months ended June 30, 1996 and the year ended December 31, 1995 . . . . . . . . . . F-29 Notes to the Pro Forma Consolidated Condensed Statement of Operations . . . . . . . F-30 Pro Forma Consolidated Condensed Balance Sheet as of June 30, 1996 . . . . . . . . . F-32 Notes to the Pro Forma Consolidated Condensed Balance Sheet . . . . . . . . . . . . F-33
F-1 13 INDEPENDENT AUDITORS' REPORT Board of Directors of Energy Development Corporation: We have audited the accompanying consolidated balance sheets of Energy Development Corporation, a wholly owned subsidiary of Enterprise Diversified Holdings Incorporated, and its subsidiaries ("EDC") as of December 31, 1994 and 1995, and the related consolidated statements of income, cash flows and changes in stockholder's equity for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of EDC's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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, such consolidated financial statements present fairly, in all material respects, the financial position of EDC at December 31, 1994 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Houston, Texas February 16, 1996 (July 2, 1996 as to Notes 1 and 10) F-2 14 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995 (Dollars in Thousands)
1993 1994 1995 --------- --------- --------- Operating revenues: Gas and oil production $249,958 $208,544 $204,050 Gas sales to affiliated companies 20,158 11,179 0 Marketing, pipeline transportation and other 8,354 10,157 8,918 Columbia bankruptcy settlement 0 0 35,034 --------- --------- --------- Total operating revenues 278,470 229,880 248,002 Operating expenses: Exploration 36,086 43,283 43,662 Lease operations 50,633 51,470 48,799 General and administrative 10,613 11,582 11,961 Depreciation, depletion and amortization 86,186 78,584 77,274 Other operations 6,384 8,087 8,120 --------- --------- --------- Total operating expenses 189,902 193,006 189,816 Other income, net 2,596 4,728 22,132 Interest expense: Interest on debt to affiliated companies 31,731 33,442 31,386 Other interest expense 217 294 469 Capitalized interest (3,124) (3,994) (4,369) --------- --------- --------- Total interest expense 28,824 29,742 27,486 --------- --------- --------- Income before income taxes 62,340 11,860 52,832 Income taxes 19,963 858 18,088 --------- --------- --------- Income before cumulative effect of accounting change 42,377 11,002 34,744 Cumulative effect of change in accounting for income taxes 1,612 0 0 --------- --------- --------- Net income $ 43,989 $ 11,002 $ 34,744 ========= ========= =========
See accompanying Notes to Consolidated Financial Statements. F-3 15 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 1994 AND 1995 (Dollars in Thousands)
1994 1995 --------- --------- Assets: Current assets: Cash and temporary cash investments $ 2,376 $ 14,269 Accounts receivable - net: Trade 42,254 52,486 Affiliated companies 7,604 254 Prepaid items 5,127 22,747 Materials and supplies inventory 1,522 1,229 ----------- --------- Total current assets 58,883 90,985 Property, plant and equipment: Property, plant and equipment, at cost (successful efforts method) 1,324,867 1,393,471 Accumulated depreciation, depletion and amortization (748,421) (786,920) ----------- --------- Net property, plant and equipment 576,446 606,551 Other assets: Accrued gas underdeliveries 19,353 12,761 Deferred taxes 32,134 0 Long term receivables 36,278 36,657 ----------- --------- Total other assets 87,765 49,418 ----------- --------- Total assets $ 723,094 $ 746,954 =========== ========= Liabilities and stockholder's equity: Current liabilities: Accounts payable and accruals: Trade $ 57,718 $ 61,881 Affiliated companies 2,371 4,818 Notes payable to affiliated companies 365,421 311,821 ----------- --------- Total current liabilities 425,510 378,520 Deferred taxes 0 9,182 Deferred revenue 5,789 4,713 Commitments and contingencies (Note 6) ----------- --------- Total liabilities 431,299 392,415 Stockholder's equity: Common stock 920 920 Paid-in capital 399,780 427,780 Accumulated deficit (108,905) (74,161) ----------- --------- Total stockholder's equity 291,795 354,539 ----------- --------- Total liabilities and stockholder's equity $ 723,094 $ 746,954 =========== =========
See accompanying Notes to Consolidated Financial Statements. F-4 16 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995 (Dollars in Thousands)
1993 1994 1995 ----------- ---------- --------- Cash flows from operating activities: Net income $43,989 $ 11,002 $ 34,744 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 86,186 78,584 77,274 Unproved leasehold impairment/abandonment 4,633 7,059 4,143 Gain on property sales (578) (1,438) (18,171) Gas balancing 7,165 6,311 5,516 Deferred income taxes 9,427 5,048 41,316 Changes in current assets and current liabilities 19,373 (3,608) (7,410) ----------- ---------- --------- Total adjustments 126,206 91,956 102,668 ----------- ---------- --------- Net cash provided by operating activities 170,195 102,958 137,412 Cash flows from investing activities: Additions to property, plant and equipment (92,012) (159,544) (132,109) Proceeds from property sales 895 6,780 32,569 Additions to/(reductions in) long term receivable 2,187 (4,165) (379) ----------- ---------- --------- Net cash used by investing activities (88,930) (156,929) (99,919) Cash flows from financing activities: Proceeds from/(repayments of) borrowings (97,805) 58,056 (53,600) Additions to paid-in capital 33,900 4,250 40,000 Dividends paid (15,600) (8,000) (12,000) ----------- ---------- --------- Net cash provided/(used) by financing activities (79,505) 54,306 (25,600) Net increase in cash and temporary cash investments 1,760 335 11,893 Cash and temporary cash investments - beginning of year 281 2,041 2,376 ----------- ---------- --------- Cash and temporary cash investments - end of year $ 2,041 $ 2,376 $ 14,269 =========== ========== ========= Changes in current assets and liabilities: Accounts receivable $ 9,497 $ 15,500 $ 854 Prepaid items (902) (2,829) (17,620) Materials and supplies inventories (482) 5 293 Accounts payable (795) (14,919) 2,596 Accrued taxes payable 1,554 (721) 212 Other current liabilities 10,501 (644) 6,255 ----------- ---------- --------- Total $ 19,373 $ (3,608) $ (7,410) =========== ========== ========= Supplemental disclosure of cash flow information: Cash paid for interest expense, net of capitalized interest $ 29,030 $ 32,587 $ 24,754 Cash paid/(received) for income taxes $6,630 $ 10,253 $(30,786)
See accompanying Notes to Consolidated Financial Statements. F-5 17 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995 (Dollars in Thousands)
1993 1994 1995 ------------- ------------ -------------- Common stock: Common stock, $1,000 stated value; authorized 7,500 shares, 920 shares issued and outstanding in each of 1993, 1994 and 1995 Balance at beginning and end of year $ 920 $ 920 $ 920 Paid-in capital: Balance at beginning of year 361,630 395,530 399,780 Capital contributions from EDHI 33,900 4,250 40,000 Dividends declared 0 0 (12,000) ------------- ------------ -------------- Balance at end of year 395,530 399,780 427,780 Accumulated deficit: Balance at beginning of year (140,296) (111,907) (108,905) Net income 43,989 11,002 34,744 Dividends declared (15,600) (8,000) 0 ------------- ------------ -------------- Balance at end of year (111,907) (108,905) (74,161) ------------- ------------ -------------- Total stockholder's equity $284,543 $291,795 $354,539 ============= ============ ==============
See accompanying Notes to Consolidated Financial Statements. F-6 18 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Energy Development Corporation ("EDC") is a wholly owned subsidiary of Enterprise Diversified Holdings Incorporated ("EDHI"), which is a wholly owned subsidiary of Public Service Enterprise Group Incorporated ("Enterprise"). EDC is engaged in the exploration for and the development, production and marketing of gas and oil reserves, with principal operations both onshore and offshore in states bordering the Gulf of Mexico and in the United Kingdom and Argentina. See Note 10 regarding the sale of EDC by EDHI which is expected to be completed on July 31, 1996. Consolidated Subsidiaries EDC has several wholly owned subsidiaries that are primarily involved in the gathering and transporting of gas and oil by pipeline and in international exploration and production activities. The consolidated financial statements of EDC include the accounts of all subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Property, Plant and Equipment EDC uses the successful efforts method of accounting for its investment in gas and oil operations. Under the successful efforts method, unproved leasehold costs are capitalized and are not amortized pending an evaluation of the exploration results. Unproved leasehold costs are assessed quarterly to determine whether an impairment of the costs of significant individual properties has occurred. The decision to impair and the amount recorded is determined based upon both geological interpretations of EDC employees and drilling activity on or near the leasehold interest. The cost of an impairment is charged to expense in the period in which it occurs. Exploratory dry holes, exploratory geological and geophysical and delay rental costs are charged to expense as incurred. Proved leasehold costs are capitalized and amortized over the proved developed and undeveloped reserves on a unit-of-production basis. Drilling and equipping costs, except exploratory dry holes, are capitalized and depreciated over the proved developed reserves on a unit-of-production basis. Estimated future abandonment costs of offshore properties are depreciated on a unit-of-production basis over the proved developed reserves. Estimated future abandonment costs of onshore properties are estimated to be offset by the salvage value of the tangible equipment. EDC periodically assesses whether the cost of proved properties has been permanently impaired, with any such impairment being charged to expense in the period in which it occurs. Impairments of proved property during 1995, 1994 and 1993 were measured by comparing the world-wide undiscounted future net cash flows to the net book value of the related assets. This test was also performed at the field level, and impairment recorded, if it was determined that the net book value could not be recovered from estimated future net cash flows, and such condition was not temporary. The impairment was measured as the excess of net book value over estimated future net cash flows. The consolidated average rate of amortization per Mcfe, exclusive of proved property impairments, was $0.7504 in 1995, $0.7319 in 1994 and $0.7105 in 1993. Proved property impairments were $9,000 in 1994 and $1.3 million in 1993. There were no proved property impairments in 1995. During 1995, 1994 and 1993, EDC acquired 0.7 Bcfe, 68.1 Bcfe and 38.8 Bcfe, respectively, of proved gas and oil reserves for $0.4 million, $69.1 million and $16.1 million, respectively. The properties acquired were obtained through several acquisitions and are primarily located in the United Kingdom, Offshore Texas, and Offshore Louisiana. F-7 19 Financial Accounting Standards Board Statement No. 121 The Financial Accounting Standards Board has issued Statement No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS 121 is effective beginning January 1, 1996 and establishes guidelines for determining and measuring asset impairment and the required timing of asset impairment evaluations. Management has addressed the requirements of this statement and believes that it will not have a significant effect on the financial condition and results of operations of EDC based upon current economic conditions. Capitalized Interest Interest is capitalized in connection with unproved leasehold costs on prospects. The capitalization rate used is based on the cost of funds outstanding during the exploration period. Materials and Supplies Inventory Inventories are stated at the lower of cost or market. The cost of inventories is determined using the average cost method. Federal Income Taxes EDC files a consolidated federal income tax return with EDHI and Enterprise. EDC and Enterprise have entered into a tax allocation agreement which provides that EDC will record its tax liability as though it were filing a separate return and will record tax benefits to the extent that Enterprise is able to receive those benefits. Deferred income taxes are provided for differences between book and taxable income, resulting primarily from differences in book and tax depletion and depreciation and the current deduction for income tax purposes of intangible drilling costs. Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes," was issued by the Financial Accounting Standards Board in February 1992. SFAS 109 required a change from an income statement approach to a balance sheet approach of accounting for income taxes. Under the balance sheet approach, deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted statutory tax rates applicable to current and future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Under SFAS 109, the effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. EDC's adoption of SFAS 109 in 1993 resulted in an increase of the deferred tax asset by $1.6 million. The total effect on net income was a $1.6 million increase, which is reflected in the results of operations for 1993 as a cumulative effect of change in accounting principle. Joint Venture Operations The terms of drilling agreements with several non-related parties provide for EDC, as operator, to make expenditures in connection with joint exploration and development ventures. Expenditures are billed to the partners as costs are paid by EDC. These billings are included in Accounts Receivable. Gas Balancing EDC follows the entitlement method of accounting for gas balancing. Gas out-of-balance conditions arise because each working interest owner in a well has the right to a specific percentage of production. Under entitlement accounting, EDC defers revenue when it sells more than its ownership percentage in a given period and accrues a receivable from other owners when it sells less than its ownership percentage. F-8 20 Natural Gas and Crude Oil Hedging EDC has been authorized by its Board of Directors to use derivatives, which may include futures contracts, options, commodity swaps and other products, for the purpose of managing price risk related to natural gas and crude oil sales and not for speculative purposes. For book purposes, gains and losses related to the hedging of anticipated transactions are deferred and recognized in income when the hedged transaction occurs. Marketing Income In addition to selling its own production, EDC sells gas and oil which it purchases from various third parties. The revenues from these sales are offset with the costs of purchasing the gas and oil and are included in "Marketing, pipeline transportation and other" revenue in the Consolidated Statements of Income. Cash and Temporary Cash Investments EDC classifies cash and investments with original maturities of three months or less as cash and temporary cash investments. Financial Instruments EDC's financial instruments consist of cash and temporary cash investments, receivables, payables and debt. As of December 31, 1995, the estimated fair values of EDC's notes to PSEG Capital Corporation ("PSEG Capital") and Enterprise Capital Funding Corporation ("EC Funding"), wholly owned subsidiaries of EDHI, were approximately $160.5 million and $167.4 million, respectively. These estimated fair values were determined based on the borrowing rates available at December 31, 1995 for debt with similar terms and maturities. The carrying amount of EDC's other financial instruments approximates fair value. Currency Translation The US dollar is the functional currency for EDC's consolidated operations. Substantially all foreign revenues and expenses are denominated in US dollars. Use of Estimates The process of preparing financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts. Reclassifications Certain amounts have been reclassified to conform with the current period's presentations. 2. STOCKHOLDER'S EQUITY Common Stock EDC had 920 shares of no-par common stock issued and outstanding as of December 31, 1995, 1994 and 1993, with a stated value of $1,000 per share. The total authorized amount as of December 31, 1995 was 7,500 shares. F-9 21 Paid-in Capital In 1995, EDHI made equity contributions of $28 million to EDC, net of dividends paid by EDC from paid-in capital of $12 million. EDC used these funds primarily to reduce debt. In 1994, EDHI made equity contributions of $4.3 million to EDC. In 1993, EDHI made equity contributions of $33.9 million to EDC. EDC used these funds primarily to finance the acquisition of Brabant Resources plc and to reduce EDC's debt. Dividends In 1995, EDC paid dividends to EDHI of $12 million, which were declared from paid-in capital. In 1994 and 1993, EDC paid dividends to EDHI of $8.0 million and $15.6 million, respectively, which were declared from retained earnings. 3. INCOME TAXES Income from continuing operations before income taxes is as follows:
------------------------------------------------------------------------------------------------- ($ in millions) 1993 1994 1995 ------------------------------------------------------------------------------------------------- US $69.8 $13.8 $ 49.3 Foreign (7.5) (1.9) 3.5 ------------------------------------------------------------------------------------------------- Total $62.3 $11.9 $ 52.8 =================================================================================================
The components of taxes on income from continuing operations are summarized as follows:
------------------------------------------------------------------------------------------------- ($ in millions) 1993 1994 1995 ------------------------------------------------------------------------------------------------- Current: US federal $ 7.7 $(3.8) $(24.4) Foreign .9 .2 .5 State .4 (.5) .7 ------------------------------------------------------------------------------------------------- Total current 9.0 (4.1) (23.2) ------------------------------------------------------------------------------------------------- Deferred: US federal 10.8 5.6 40.3 Foreign .2 .3 .8 State .0 (.9) .2 ------------------------------------------------------------------------------------------------- Total deferred 11.0 5.0 41.3 ------------------------------------------------------------------------------------------------- Total income taxes $20.0 $ .9 $ 18.1 =================================================================================================
F-10 22 A reconciliation of income taxes calculated at the US federal statutory rate of 35% of income before income taxes and the income tax provision is as follows:
------------------------------------------------------------------------------------------------- ($ in millions) 1993 1994 1995 ------------------------------------------------------------------------------------------------- Federal income tax expense at statutory rate $21.8 $4.2 $18.5 Foreign taxes for which benefits are not recognized 2.4 (0.2) 0.0 State income taxes, net of federal income taxes 0.2 (1.6) 0.6 Tight gas sands tax credits (3.7) (1.6) (1.0) Deferred income tax rate 1% change (0.8) 0.0 0.0 Other 0.1 0.1 0.0 ------------------------------------------------------------------------------------------------- Income tax expense $20.0 $ 0.9 $18.1 =================================================================================================
As discussed in Note 1, Summary of Significant Accounting Policies, EDC adopted SFAS 109 as of the beginning of 1993, which increased earnings by $1.6 million, and is reported separately in the Consolidated Statements of Income. The federal deferred tax liability at December 31, 1995 and federal deferred tax asset at December 31, 1994 are primarily composed of the difference between the tax and the book basis of property, plant and equipment. The state deferred tax asset is primarily composed of the effects of Louisiana net operating loss expected to be utilized. At December 31, 1995, EDC had approximately $56 million in net operating loss carryforwards expiring from 2003 to 2010 available to offset future state taxable income. Included in the deferred tax liability at December 31, 1995 and the deferred tax asset at December 31, 1994 is a deferred state tax asset of $4.4 million that is primarily composed of the difference between the tax and the book basis of the property, plant and equipment and state tax net operating loss carryforward. The valuation allowance related to the deferred state tax asset was $2.4 million at both December 31, 1995 and 1994 and resulted from the uncertainty of the utilization of state tax net operating loss carryforward to reduce future taxable income. F-11 23 The significant components of accumulated deferred income taxes - non-current attributable to income from continuing operations were as follows:
------------------------------------------------------------------------------------------------- ($ in millions) 1994 1995 ------------------------------------------------------------------------------------------------- DEFERRED TAX ASSETS: Property and leasehold costs $ 27.9 $ 35.7 Excess of book over tax depreciation, depletion and amortization 195.1 191.1 Federal alternative minimum tax credit carryforward(1) 28.6 19.4 Other 1.7 1.1 ------------------------------------------------------------------------------------------------- TOTAL DEFERRED TAX ASSETS 253.3 247.3 ------------------------------------------------------------------------------------------------- DEFERRED TAX LIABILITIES: Property, plant and equipment 26.5 30.3 Exploration and intangible well drilling costs 188.5 211.1 Investments in partnership, due to difference in depreciation 1.5 1.5 Disposition of assets, book/tax difference 3.0 2.5 Other 1.7 11.1 ------------------------------------------------------------------------------------------------- TOTAL DEFERRED TAX LIABILITIES 221.2 256.5 ------------------------------------------------------------------------------------------------- TOTAL NET DEFERRED TAX LIABILITIES/(ASSETS) $ (32.1) $ 9.2 =================================================================================================
(1) Available to reduce future U.S. federal income taxes over an indefinite period. 4. RELATED PARTY TRANSACTIONS PSE&G In 1993 and through September 30, 1994, EDC supplied and transported gas for PSE&G. The New Jersey Board of Public Utilities ("BPU") regulates the rates of PSE&G and its ability to recover from its customers the price paid to EDC for gas. The price received from PSE&G was determined each month and included two components: a commodity rate and a monthly demand charge. The commodity rate generally reflected the current month's spot market price for gas delivered at the wellhead. The monthly demand charge was fixed and added to the commodity rate. In accordance with a BPU ruling, PSE&G ceased gas purchases from EDC as of September 30, 1994. As a result, gas transportation services provided to PSE&G also ceased. EDC has incurred no problems in finding a market for the production that would have been sold to PSE&G after September 1994. EDC's operating revenues include billings to PSE&G, net of royalties paid to various unrelated parties, of approximately $39.8 million and $58.0 million for the years ended December 31, 1994 and 1993, respectively. Of these amounts, $11.2 million and $20.2 million were sales of natural gas produced by EDC and $1.5 million and $1.7 million were for gas transportation services for the years ended December 31, 1994 and 1993, respectively. Also included were F-12 24 $27.1 million and $36.1 million for gas sold to PSE&G that was purchased from third parties by EDC at a cost of $25.3 million and $33.4 million for the years ended December 31, 1994 and 1993, respectively. Payroll and related fringe benefit costs of PSE&G employees and other expenses incurred by PSE&G on behalf of EDC are billed on a monthly basis. Such costs amounted to approximately $0.8 million, $0.7 million and $0.5 million for the years ended December 31, 1995, 1994 and 1993, respectively. Employees of EDC who have completed one year of service become participants in a non-contributory pension plan. This plan is administered by PSE&G, and costs related to Company employees are billed on a monthly basis. Such costs amounted to approximately $0.9 million, $0.8 million and $0.6 million for the years ended December 31, 1995, 1994 and 1993, respectively. PSEG Capital, EC Funding EDC has executed and delivered global demand promissory notes evidencing unsecured loans from PSEG Capital and EC Funding. Each note provides for borrowings at interest rates based upon the lender's average cost of debt. The effective interest rates for borrowings from PSEG Capital and EC Funding were 9.27% and 9.03%, respectively in 1995, 9.66% and 11.21%, respectively in 1994, and 10.11% and 7.40%, respectively in 1993. Interest expense incurred on the notes to PSEG Capital and EC Funding were $20.0 million and $11.4 million, respectively in 1995, $23.0 million and $10.4 million, respectively in 1994, and $20.9 million and $10.8 million, respectively in 1993. Borrowings under the notes to PSEG Capital and EC Funding were $152.3 million and $159.5 million, respectively at December 31, 1995, $238.9 million and $126.5 million, respectively at December 31, 1994, and $218.2 million and $89.2 million, respectively at December 31, 1993. Under EC Funding's borrowing agreements, EDC must have a consolidated indebtedness to consolidated tangible net worth ratio not to exceed 1.75:1. Enterprise, EDHI EDC was billed administrative overheads of $0.5 million, $0.4 million and $0.3 million by Enterprise in 1995, 1994 and 1993, respectively. These administrative overheads are allocated to EDC based upon EDC's percentage of total Enterprise assets. EDC was billed administrative overheads of $1.8 million, $1.8 million and $1.9 million by EDHI in 1995, 1994 and 1993, respectively. The administrative overheads are allocated to EDC based upon EDC's percentage of total EDHI equity, excluding accumulated deficit, plus contingent obligations. Management believes these allocation methods are reasonable. However, such allocated amounts may not be indicative of amounts incurred for these expenses if EDC were a stand alone entity. Entech Enterprises, Inc. During 1989, EDC entered into an incentive compensation agreement with Entech Enterprises, Inc. ("Entech"), whose president was also the president of EDC and a member of EDC's Board of Directors from January 1, 1989 until December 19, 1994. The incentive compensation agreement is in the form of a Participation Agreement, as amended ("Agreement"). Under the Agreement, Entech is entitled to a 5% interest in all new properties, which are primarily properties acquired by EDC subsequent to January 1, 1989 and prior to December 31, 1993. EDC advances for the benefit of Entech and pays 100% of Entech's obligations with respect to all new properties' costs. Interest accrues on these advances at a rate of Chase Manhattan Bank prime plus one percent until such advances are repaid. EDC looks solely to Entech's interest in the conveyed properties and the proceeds therefrom for the repayment of all advances and interest. Advances and interest are repaid monthly in installments equal to 97% of Entech's Net Cash Flow attributable to the preceding month for those new properties. The remaining 3% of Entech's Net Cash Flow is distributed to Entech by EDC. New properties' costs advanced to Entech during 1995, 1994 and 1993 were approximately $1.1 million, $8.7 million and $4.6 million, respectively. Interest income attributable to 1995, 1994 and 1993 was approximately $3.2 million, $2.8 million and $2.2 million, respectively. Net Cash Flow was sufficient to pay all accrued interest as of December 31, 1995. In addition, Net Cash Flow attributable to repayment of the advance in 1995, 1994 and 1993 was $0.4 million, $4.6 million and $6.8 F-13 25 million, respectively. The advance balance outstanding was $36.7 million, $36.0 million and $31.8 million at December 31, 1995, 1994 and 1993, respectively. 5. NATURAL GAS AND CRUDE OIL HEDGING EDC utilizes natural gas and crude oil options and futures contracts in order to limit EDC's exposure to downward price swings on natural gas and crude oil sales and to protect targeted price levels. EDC had natural gas futures contracts sold and outstanding that hedged 21.1 million and 10.7 million MMBTU at December 31, 1995 and 1994, respectively at an average price of $1.93 and $1.95 per MMBTU, respectively. At December 31, 1995, EDC had sold and outstanding crude oil futures contracts which hedged 1.5 million barrels at an average price of $17.74 per barrel. All contracts outstanding at December 31, 1995 and 1994 were New York Mercantile Exchange traded contracts. EDC had no outstanding natural gas or crude oil hedge positions at December 31, 1993. These contracts are accounted for as hedges for book purposes, and accordingly, gains and losses are deferred until the related sales are made. The net unrealized deferred loss on outstanding contracts at December 31, 1995 was $5.1 million. The losses actually realized on these contracts, if any, are expected to be offset by the higher cash proceeds received from the hedged item when produced and sold. 6. COMMITMENTS AND CONTINGENCIES EDC is a party to lawsuits and claims arising in the ordinary course of business. EDC believes, based on its current knowledge and the advice of its counsel, that all such lawsuits and claims would not have a material adverse effect on its financial condition, results of operations and cash flows. EDC has operating leases which expire over the next five years with aggregate future minimum lease payments totaling $6.4 million. Minimum lease payments during the next five years for leases having initial or remaining terms in excess of one year are as follows:
--------------------------------------------------------------------------------- ($ in millions) --------------------------------------------------------------------------------- 1996 $1.8 1997 2.2 1998 2.0 1999 .2 2000 .2 --------------------------------------------------------------------------------- Total minimum lease payments $6.4 =================================================================================
Rent expense for 1995, 1994 and 1993 was approximately $2.3 million, $2.3 million and $1.8 million, respectively. 7. COLUMBIA GAS TRANSMISSION COMPANY ("COLUMBIA") BANKRUPTCY SETTLEMENT Columbia filed for protection from its creditors in July 1991 under Chapter 11 of the bankruptcy laws. EDC was an initial creditor because Columbia breached a take-or-pay natural gas purchase contract. Columbia subsequently rejected EDC's contract shortly after its bankruptcy filing. Columbia's Plan of Reorganization ("Plan") was approved in November 1995 and EDC received a distribution of $36.1 million under the Plan in the same month. Of the amount received, $35.0 million was included in 1995 operating revenues. F-14 26 8. GEOGRAPHIC DATA Operating revenues, income before income taxes and identifiable assets by geographic area were as follows:
-------------------------------------------------------------------------------------- ($ in millions) 1993 1994 1995 -------------------------------------------------------------------------------------- Operating revenues: United States $259.9 $197.1 $206.9 United Kingdom 10.8 26.0 33.2 Other foreign 7.8 6.8 7.9 -------------------------------------------------------------------------------------- Operating revenues $278.5 $229.9 $248.0 ====================================================================================== Income before income taxes: United States $ 95.9 $ 38.6 $ 71.6 United Kingdom (.2) 3.7 8.0 Other foreign (4.6) (.7) .7 -------------------------------------------------------------------------------------- 91.1 41.6 80.3 Interest expense (28.8) (29.7) (27.5) -------------------------------------------------------------------------------------- Income before income taxes $ 62.3 $ 11.9 $ 52.8 ====================================================================================== Identifiable assets: United States $621.4 $625.4 $644.6 United Kingdom 20.8 62.6 65.8 Other foreign 33.2 35.1 36.6 -------------------------------------------------------------------------------------- Identifiable assets $675.4 $723.1 $747.0 ======================================================================================
9. QUARTERLY RESULTS (UNAUDITED)
--------------------------------------------------------------------------------------------- ($ in millions) Quarter Ended March 31 June 30 September 30 December 31 --------------------------------------------------------------------------------------------- 1994: Revenues $65.7 $58.1 $55.0 $51.1 Operating income 19.6 8.6 2.0 6.7 Net income/(loss) 8.5 1.8 (2.8) 3.5 1995: Revenues $48.1 $54.8 $49.7 $95.4 Operating income/(loss) 5.7 5.4 (1.0) 48.1 Net income/(loss) .1 .1 (2.3) 36.8 ---------------------------------------------------------------------------------------------
During the fourth quarter of 1995, EDC recorded the settlement of the Columbia bankruptcy which increased revenues and operating income by $35.0 million and net income by $22.8 million. During the same quarter, EDC sold property and realized a gain which increased net income by $9.1 million. F-15 27 10. SUBSEQUENT EVENTS On December 6, 1995, Enterprise announced that it intended to pursue divestiture of its ownership interest in EDC. In connection with the planned divestiture, EDC declared dividends of $100 million and $75 million on January 31, 1996 and April 15, 1996, respectively. The dividends were funded by additional intercompany indebtedness of $175 million. On July 1, 1996, EDHI entered into an agreement to sell all of the outstanding common stock of EDC to Samedan Oil Corporation, a wholly owned subsidiary of Noble Affiliates, Inc. The sale is expected to be completed on July 31, 1996. F-16 28 SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (UNAUDITED) Capitalized Costs Relating to Gas and Oil Producing Activities
- ---------------------------------------------------------------------------------------------------------------- ($ in millions) United United Other States Kingdom Argentina Foreign Total - ---------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------- December 31, 1993 Unproved properties, not being amortized $ 51.2 $ 1.9 $ 0.0 $ 0.6 $ 53.7 Proved properties 1,075.9 17.9 26.7 0.0 1,120.5 - ---------------------------------------------------------------------------------------------------------------- Total capitalized costs 1,127.1 19.8 26.7 0.6 1,174.2 Less accumulated depreciation, depletion and amortization 673.4 3.2 2.0 0.0 678.6 - ---------------------------------------------------------------------------------------------------------------- Net capitalized costs (a) $ 453.7 $ 16.6 $ 24.7 $ 0.6 $ 495.6 ================================================================================================================ December 31, 1994 Unproved properties, not being amortized $ 63.6 $ 4.1 $ 0.2 $ 0.0 $ 67.9 Proved properties 1,141.6 56.2 28.3 0.0 1,226.1 - ---------------------------------------------------------------------------------------------------------------- Total capitalized costs 1,205.2 60.3 28.5 0.0 1,294.0 Less accumulated depreciation, depletion and amortization 714.0 12.1 3.1 0.0 729.2 - ---------------------------------------------------------------------------------------------------------------- Net capitalized costs (a) $ 491.2 $ 48.2 $ 25.4 $ 0.0 $ 564.8 ================================================================================================================ December 31, 1995 Unproved properties, not being amortized $ 71.5 $ 3.4 $ 0.2 $ 2.4 $ 77.5 Proved properties 1,188.5 62.1 32.8 0.0 1,283.4 - ---------------------------------------------------------------------------------------------------------------- Total capitalized costs 1,260.0 65.5 33.0 2.4 1,360.9 Less accumulated depreciation, depletion and amortization 740.5 20.3 4.4 0.0 765.2 - ---------------------------------------------------------------------------------------------------------------- Net capitalized costs (a) $ 519.5 $ 45.2 $ 28.6 $ 2.4 $ 595.7 ================================================================================================================
(a) Excludes capitalized costs related to pipelines, plants and other miscellaneous non-gas and oil producing assets. F-17 29 Costs Incurred in Gas and Oil Producing Activities
- ------------------------------------------------------------------------------------------------------------------------------- ($ in millions) United United Other States Kingdom Argentina Foreign Total - ------------------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Property acquisition - Proved properties $ 1.9 $14.2 $ 0.0 $ 0.0 $ 16.1 Unproved properties 4.4 2.0 0.0 0.0 6.4 Exploration (b) 25.5 2.2 0.0 7.9 35.6 Development 48.0 2.9 3.2 0.0 54.1 - ------------------------------------------------------------------------------------------------------------------------------- Total costs incurred (a) $ 79.8 $21.3 $ 3.2 $ 7.9 $112.2 =============================================================================================================================== Year ended December 31, 1994 Property acquisition - Proved properties $ 33.8 $35.3 $ 0.0 $ 0.0 $ 69.1 Unproved properties 14.9 2.7 0.1 0.0 17.7 Exploration (b) 35.3 3.9 0.0 2.4 41.6 Development 53.4 6.2 1.7 0.0 61.3 - ------------------------------------------------------------------------------------------------------------------------------- Total costs incurred (a) $137.4 $48.1 $ 1.8 $ 2.4 $189.7 =============================================================================================================================== Year ended December 31, 1995 Property acquisition - Proved properties $ 0.4 $ 0.0 $ 0.0 $ 0.0 $ 0.4 Unproved properties 16.9 0.3 0.0 1.1 18.3 Exploration (b) 35.7 3.7 0.0 3.6 43.0 Development 81.1 7.0 4.4 0.0 92.5 - ------------------------------------------------------------------------------------------------------------------------------- Total costs incurred (a) $134.1 $11.0 $ 4.4 $ 4.7 $154.2 ===============================================================================================================================
(a) Includes costs whether capitalized or expensed as incurred. (b) Includes 1993, 1994 and 1995 capitalized interest of $3.1, $4.0 and $4.4 million, respectively. F-18 30 Results of Operations from Gas and Oil Producing Activities
- ---------------------------------------------------------------------------------------------------------------------- ($ in millions) United United Other States Kingdom Argentina Foreign Total - ---------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1993 Revenues $251.5 $10.8 $ 7.8 $ 0.0 $270.1 Exploration costs 13.0 2.1 0.0 6.0 21.1 Production costs 42.9 5.1 2.6 0.0 50.6 Depreciation, depletion and amortization 80.4 2.3 1.0 0.0 83.7 - ---------------------------------------------------------------------------------------------------------------------- 115.2 1.3 4.2 (6.0) 114.7 Income tax expense (a) 36.7 0.1 1.5 (2.1) 36.2 - ---------------------------------------------------------------------------------------------------------------------- Results of operations (b) $ 78.5 $ 1.2 $ 2.7 $ (3.9) $ 78.5 ====================================================================================================================== Year ended December 31, 1994 Revenues $187.0 $25.9 $ 6.8 $ 0.0 $219.7 Exploration costs 22.3 4.1 0.0 1.7 28.1 Production costs 42.2 6.7 2.6 0.0 51.5 Depreciation, depletion and amortization 67.1 7.9 1.1 0.0 76.1 - ---------------------------------------------------------------------------------------------------------------------- 55.4 7.2 3.1 (1.7) 64.0 Income tax expense (a) 18.4 0.2 1.1 (0.6) 19.1 - ---------------------------------------------------------------------------------------------------------------------- Results of operations (b) $ 37.0 $ 7.0 $ 2.0 $ (1.1) $ 44.9 ====================================================================================================================== Year ended December 31, 1995 Revenues $198.7 $32.4 $ 8.0 $ 0.0 $239.1 Exploration costs 22.3 3.5 0.0 .6 26.4 Production costs 38.3 7.7 2.8 0.0 48.8 Depreciation, depletion and amortization 65.2 8.2 1.3 0.0 74.7 - ---------------------------------------------------------------------------------------------------------------------- 72.9 13.0 3.9 (.6) 89.2 Income tax expense (a) 25.1 1.1 1.4 (.2) 27.4 - ---------------------------------------------------------------------------------------------------------------------- Results of operations (b) $ 47.8 $11.9 $ 2.5 $(.4) $ 61.8 ======================================================================================================================
(a) Income tax expense is calculated by applying the statutory rates to pre-tax income, taking into consideration any permanent differences and tax credits. (b) Excludes general corporate overhead, interest costs and other income. F-19 31 Estimated Proved Gas and Oil Reserves Net quantities of proved and proved developed reserves of crude oil and natural gas for 1993, 1994 and 1995 are set forth in the tables below. Proved developed gas and oil reserves can be expected to be recovered through existing wells with existing equipment and operating methods. Proved gas and oil reserves that are not developed are expected to be recovered from new wells or from existing wells where a relatively major expenditure is required to establish production.
- ---------------------------------------------------------------------------------------------------------------------- Gas (Bcf) United United States Kingdom Argentina Total - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1992 554 0 0 554 Purchases of reserves in place 2 8 0 10 Sales of reserves in place (1) 0 0 (1) Revisions of previous estimates 37 3 0 40 Extensions, discoveries and other additions 31 0 0 31 Production (95) (1) 0 (96) - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1993 528 10 0 538 Purchases of reserves in place 28 32 0 60 Sales of reserves in place 0 (4) 0 (4) Revisions of previous estimates 17 (1) 5 21 Extensions, discoveries and other additions 62 0 0 62 Production (79) (4) 0 (83) - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1994 556 33 5 594 Purchases of reserves in place 1 0 0 1 Sales of reserves in place (6) (2) 0 (8) Revisions of previous estimates (11) 12 0 1 Extensions, discoveries and other additions 112 5 0 117 Production (71) (4) 0 (75) - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1995 581 44 5 630 ====================================================================================================================== Proved developed reserves at December 31, 1992 514 0 0 514 1993 486 6 0 492 1994 499 20 4 523 1995 452 22 3 477 ======================================================================================================================
F-20 32
- ---------------------------------------------------------------------------------------------------------------------- Oil (MBbls) United United States Kingdom Argentina Total - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1992 22,027 0 15,409 37,436 Purchases of reserves in place 107 4,750 0 4,857 Sales of reserves in place (60) 0 0 (60) Revisions of previous estimates 1,600 709 16 2,325 Extensions, discoveries and other additions 4,353 0 0 4,353 Production (2,610) (662) (535) (3,807) - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1993 25,417 4,797 14,890 45,104 Purchases of reserves in place 159 1,203 0 1,362 Sales of reserves in place (85) (2) 0 (87) Revisions of previous estimates (102) 1,475 (863) 510 Extensions, discoveries and other additions 6,134 0 0 6,134 Production (2,394) (1,149) (517) (4,060) - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1994 29,129 6,324 13,510 48,963 Purchases of reserves in place 39 0 0 39 Sales of reserves in place (3,362) (179) 0 (3,541) Revisions of previous estimates (1,474) 1,871 118 515 Extensions, discoveries and other additions 5,746 666 0 6,412 Production (2,481) (995) (540) (4,016) - ---------------------------------------------------------------------------------------------------------------------- Proved reserves at December 31, 1995 27,597 7,687 13,088 48,372 ====================================================================================================================== Proved developed reserves at December 31, 1992 16,862 0 8,550 25,412 1993 20,589 4,736 8,022 33,347 1994 24,160 5,958 6,505 36,623 1995 19,497 6,756 6,658 32,911 ======================================================================================================================
The proved reserve estimates presented herein for each of the three years ended December 31, 1995 were prepared by EDC, and approximately 80% of such reserve estimates were reviewed and found to be, in the aggregate, reasonable and in accordance with generally accepted engineering and evaluation principles by Miller and Lents, Ltd., independent petroleum engineers. F-21 33 Standardized Measure The amounts presented below are based upon the methods and assumptions prescribed in the Statement of Financial Accounting Standards No. 69 ("SFAS 69"). The disclosure is a tool which is intended to provide a uniform calculation for entities with gas and oil reserves that will allow comparability among entities. It is not intended to be an estimate of fair market value or the net present value of future cash flows.
- ---------------------------------------------------------------------------------------------------------------------- ($ in millions) United United States Kingdom Argentina Total - ---------------------------------------------------------------------------------------------------------------------- December 31, 1993 Future cash inflows (a) $1,621.8 $ 98.8 $213.0 $1,933.6 Future costs - Production (b) (272.5) (60.4) (102.3) (435.2) Development and abandonment (b) (68.1) (12.9) (22.5) (103.5) Future income taxes (c) (257.2) (3.5) (18.0) (278.7) - ---------------------------------------------------------------------------------------------------------------------- Future net cash flows 1,024.0 22.0 70.2 1,116.2 - ---------------------------------------------------------------------------------------------------------------------- 10% annual discount (d) (260.1) (3.9) (28.6) (292.6) - ---------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 763.9 $ 18.1 $ 41.6 $ 823.6 ====================================================================================================================== December 31, 1994 Future cash inflows (a) $1,389.6 $203.0 $194.9 $1,787.5 Future costs - Production (b) (258.6) (102.4) (65.7) (426.7) Development and abandonment (b) (75.5) (20.8) (28.4) (124.7) Future income taxes (c) (214.2) (14.5) (22.7) (251.4) - ---------------------------------------------------------------------------------------------------------------------- Future net cash flows 841.3 65.3 78.1 984.7 - ---------------------------------------------------------------------------------------------------------------------- 10% annual discount (d) (221.3) (13.8) (32.8) (267.9) - ---------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows $ 620.0 $ 51.5 $ 45.3 $ 716.8 - ---------------------------------------------------------------------------------------------------------------------- December 31, 1995 Future cash inflows (a) $1,909.5 $262.1 $216.2 $2,387.8 Future costs - Production (b) (281.7) (115.0) (63.0) (459.7) Development and abandonment (b) (86.9) (23.5) (22.0) (132.4) Future income taxes (c) (406.3) (33.6) (35.9) (475.8) - ---------------------------------------------------------------------------------------------------------------------- Future net cash flows 1,134.6 90.0 95.3 1,319.9 - ---------------------------------------------------------------------------------------------------------------------- 10% annual discount (d) (330.8) (23.2) (37.3) (391.3) ====================================================================================================================== Standardized measure of discounted future net cash flows $ 803.8 $ 66.8 $ 58.0 $ 928.6 ======================================================================================================================
(a) Calculated using year-end gas and oil prices (adjusted for contractual price changes which can be determined) applied to the estimated future production of proved reserves assuming continuation of year-end economic conditions. (b) Estimated based upon year-end costs held constant in the future. (c) Calculated using statutory tax rates and adjusted for permanent differences and tax credits. (d) The 10% discount rate is prescribed in SFAS 69 and is not necessarily representative of EDC's cost of capital. F-22 34 Principal Sources of Change in the Standardized Measure
- ---------------------------------------------------------------------------------------------------------------------- ($ in millions) 1993 1994 1995 - ---------------------------------------------------------------------------------------------------------------------- Standardized measure - beginning of year $ 822.0 $ 823.6 $ 716.8 Sales and transfers, net of production costs (218.7) (164.3) (150.1) Net change in sales and transfer prices, net of production costs (16.7) (211.9) 299.3 Extensions and discoveries and improved recovery, net of future production and development costs 70.5 124.4 168.2 Changes in estimated future development costs (18.6) (12.5) (11.6) Development costs incurred during the period that reduced future development costs 12.0 14.7 43.8 Revisions of quantity estimates 66.4 24.3 4.4 Accretion of discount 93.6 94.6 82.6 Net change in income taxes (8.5) 13.1 (150.3) Purchase of reserves in place 27.3 80.5 0.7 Sale of reserves in place (1.4) (1.1) (23.8) Changes in production rates (timing) and other (4.3) (68.6) (51.4) - ---------------------------------------------------------------------------------------------------------------------- Standardized measure - end of year $ 823.6 $ 716.8 $ 928.6 ======================================================================================================================
F-23 35 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED CONDENSED STATEMENTS OF INCOME FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996 (UNAUDITED) (IN THOUSANDS)
1995 1996 ------------------- ------------------ REVENUES: Oil and gas sales and royalties $ 99,439 $ 121, 074 Gathering, marketing and processing 47,635 61,774 Other income 4,071 3,506 ------------------- ------------------ 151,145 186,354 COSTS AND EXPENSES: Oil and gas operations 27,775 29,633 Oil and gas exploration 18,636 29,055 Gathering, marketing and processing 45,463 58,001 Depreciation, depletion and amortization 39,262 65,820 Selling, general and administrative 6,140 5,121 Interest 15,072 15,489 ------------------- ------------------ 152,348 203,119 ------------------- ------------------ INCOME (LOSS) BEFORE TAXES (1,203) (16,765) INCOME TAX BENEFIT (641) (7,732) ------------------- ------------------ NET INCOME (LOSS) $ (562) $ (9,033) =================== ==================
See accompanying Notes to Consolidated Condensed Financial Statements. F-24 36 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED CONDENSED BALANCE SHEET AS OF JUNE 30, 1996 (UNAUDITED) (IN THOUSANDS)
June 30, 1996 --------------- ASSETS: Current assets $ 73,563 Property, plant and equipment 604,795 Other 48,846 --------------- $ 727,204 =============== LIABILITIES AND STOCKHOLDER'S EQUITY: Current liabilities $ 60,784 Payables - affiliated companies 487,818 Deferred incomes taxes 7,172 Other deferred credits and noncurrent liabilities 4,425 Stockholder's equity 167,005 ---------------- $ 727,204 ================
See accompanying Notes to Consolidated Condensed Financial Statements. F-25 37 ENERGY DEVELOPMENT CORPORATION CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996 (UNAUDITED) (IN THOUSANDS)
1995 1996 ----------------- ---------------- Cash flow from operating activities: Net income (loss) $ (562) $ (9,033) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 39,262 65,820 Unproved leasehold impairment/abandonment 2,021 4,962 Gain on property sales (301) (161) Gas balancing 768 776 Deferred income taxes 7,410 (2,010) Accrued/deferred revenue 1,148 (481) Changes in current assets and current liabilities: Accounts receivable 1,059 (8,700) Prepaid items 1,172 11,689 Materials and supplies inventories 10 (251) Accounts payable (271) 6,946 Accrued taxes payable 332 (320) Other current liabilities (4,900) (9,293) ---------------- ---------------- Total adjustments 47,710 68,977 ---------------- ---------------- Net cash provided by operating activities 47,148 59,944 Cash flows from investing activities: Additions to property, plant and equipment (52,879) (63,572) Additions to (reductions in) long-term receivable (662) 868 ---------------- ---------------- Net cash used by investing activities (53,541) (62,704) Cash flows from financing activities: Proceeds from (repayments of) borrowings (29,600) 168,691 Additions to paid-in capital 40,000 0 Dividends paid (3,550) (178,500) ---------------- ---------------- Net cash provided (used) by financing activities 6,850 (9,809) Net increase in cash and temporary cash investments 457 (12,569) Cash and temporary cash investments - beginning of period 2,376 14,269 ---------------- ---------------- Cash and temporary cash investments - end of period $ 2,833 $ 1,700 ================ ================ Supplemental disclosure of cash flow information: Cash paid for interest expense, net of capitalized interest $ 13,807 $ 12,550 Cash paid (received) for income taxes $ (9,097) $ (1,573)
See accompanying Notes to Consolidated Condensed Financial Statements. F-26 38 NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Unaudited) In the opinion of the Company, the accompanying unaudited consolidated condensed financial statements of EDC contain all adjustments, consisting only of necessary and normal recurring adjustments, necessary to present fairly EDC's financial position as of June 30, 1996, and the statements of income for the six month periods ended June 30, 1996 and 1995 and the cash flows for the six month periods ended June 30, 1996 and 1995. These consolidated condensed financial statements of EDC should be read in conjunction with the audited consolidated financial statements of EDC and the notes thereto included elsewhere in this Form 8-K/A (No. 1). (1) DEPRECIATION, DEPLETION AND AMORTIZATION During the six months ended June 30, 1996, depreciation, depletion and amortization increased $26.6 million over the comparable period in 1995, or an increase from $.80 per Mcfe to $1.31 per Mcfe, primarily as a result of downward revisions to oil and gas reserve estimates made during the first six months of 1996. (2) CONTINGENCIES EDC is a party to lawsuits and claims arising in the ordinary course of business. EDC believes, based on its current knowledge and the advice of its counsel, that all such lawsuits and claims would not have a material adverse effect on its financial condition, results of operations and cash flows. (3) DIVIDENDS In the six months ended June 30, 1996 and 1995, EDC paid dividends to EDHI of $178.5 million and $3.55 million, respectively, which were declared from paid-in capital. (4) SUBSEQUENT EVENT On July 31, 1996, Samedan Oil Corporation, a wholly owned subsidiary of Noble Affiliates, Inc., acquired all the outstanding common stock of EDC for approximately $768 million in cash. F-27 39 NOBLE AFFILIATES, INC. AND SUBSIDIARIES PRO FORMA CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (Unaudited) The unaudited pro forma consolidated condensed financial statements set forth below present the pro forma consolidated condensed statement of operations of Noble Affiliates, Inc. and Energy Development Corporation ("EDC") (together, the "Company") for the six months ended June 30, 1996 as if the acquisition of EDC (the "EDC Acquisition") and the financing thereof had occurred on January 1, 1996 and the pro forma consolidated condensed statement of operations of the Company for the year ended December 31, 1995 as if the EDC Acquisition and the financing thereof had occurred on January 1, 1995. Also presented is the pro forma consolidated condensed balance sheet of the Company at June 30, 1996 as if the EDC Acquisition and the financing thereof had occurred on such date. The unaudited pro forma consolidated condensed financial statements have been prepared on the basis of assumptions described in the notes thereto and include assumptions relating to the allocation of the consideration paid for EDC to the assets and liabilities of EDC based on preliminary estimates of their respective fair values. The EDC Acquisition has been accounted for using the purchase method of accounting. The unaudited pro forma consolidated condensed financial statements do not necessarily represent what the Company's financial position and results of operations would have been if the EDC Acquisition and the financing thereof had actually been completed as of the dates indicated, and they are not intended to project the Company's financial position or results of operations for any future period. The unaudited pro forma consolidated condensed financial statements should be read in conjunction with the consolidated financial statements of Noble Affiliates, Inc. and the related notes thereto incorporated by reference in the Company's annual report on Form 10-K for the year ended December 31, 1995, the consolidated condensed financial statements of Noble Affiliates, Inc. and the related notes thereto contained in the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1996, EDC's audited financial statements as of December 31, 1994 and 1995 and for each of the three years in the period ended December 31, 1995 and the related notes thereto included elsewhere in this Form 8-K/A (No. 1) and EDC's unaudited consolidated condensed financial statements as of June 30, 1995 and 1996 and for the six months then ended and the related notes thereto included elsewhere in this Form 8-K/A (No. 1). F-28 40 NOBLE AFFILIATES, INC. AND SUBSIDIARIES PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS)
SIX MONTHS ENDED JUNE 30, 1996(1) ----------------------------------------------------------------------- ENERGY NOBLE DEVELOPMENT AFFILIATES, INC. CORPORATION ADJUSTMENTS PRO FORMA ---------------- ----------- ----------- ----------- REVENUES: Oil and gas sales and royalties $ 227,937 $ 121,074 $ $ 349,011 Gathering, marketing and processing 122,087 61,774 183,861 Other income 3,971 3,506 7,477 ------------ --------- ------------ ---------- 353,995 186,354 --- 540,349 ------------ --------- ------------ ---------- COSTS AND EXPENSES: Oil and gas operations 49,358 29,633 78,991 Oil and gas exploration 20,455 29,055 (7,346)(c) 42,164 Gathering, marketing and processing 110,895 58,001 168,896 Depreciation, depletion and amortization 82,926 65,820 2,700 (a) 151,446 Selling, general and administrative 18,885 5,121 (169)(b)(c) 23,837 Interest 9,799 15,489 7,142 (d) 32,430 ------------ --------- ----------- ---------- 292,318 203,119 2,327 497,764 ------------ --------- ----------- ---------- INCOME BEFORE TAXES 61,677 (16,765) (2,327) 42,585 INCOME TAX PROVISION 22,139 (7,732) (838)(e) 13,569 ------------ --------- ----------- ---------- NET INCOME $ 39,538 $ (9,033) $ (1,489) $ 29,016 ============ ========= =========== ========== NET INCOME PER COMMON SHARE $ 0.78 $ 0.58 ============ ========== FULLY DILUTED EARNINGS PER SHARE $ 0.75 $ 0.56 ============ ==========
YEAR ENDED DECEMBER 31, 1995(1) ----------------------------------------------------------------------- ENERGY NOBLE DEVELOPMENT AFFILIATES, INC. CORPORATION ADJUSTMENTS PRO FORMA ---------------- ------------- ----------- ----------- REVENUES: Oil and gas sales and royalties $ 328,134 $ 204,050 $ $ 532,184 Gathering, marketing and processing 112,702 90,049 202,751 Other income(2) 46,182 61,640 107,822 --------------- ------------- ----------- ----------- 487,018 355,739 --- 842,757 --------------- ------------- ----------- ----------- COSTS AND EXPENSES: Oil and gas operations 33,246 56,919 90,165 Oil and gas exploration 81,735 43,662 (15,339)(c) 110,058 Gathering, marketing and processing 107,867 85,605 193,472 Depreciation, depletion and amortization(2) 200,914 77,274 57,375 (a) 335,563 Selling, general and administrative 36,514 11,961 1,433 (b)(c) 49,908 Interest 18,744 27,486 17,240 (d) 63,470 --------------- ------------- ---------- ----------- 479,020 302,907 60,709 842,636 --------------- ------------- ---------- ----------- INCOME BEFORE TAXES 7,998 52,832 (60,709) 121 INCOME TAX PROVISION 3,912 18,088 (21,952)(e) 48 --------------- ------------- ---------- ----------- NET INCOME $ 4,086 $ 34,744 $ (38,757) $ 73 =============== ============= ========== =========== NET INCOME PER COMMON SHARE $ 0.08 $ 0.00 =============== =========== FULLY DILUTED EARNINGS PER SHARE $ 0.08 $ 0.00 =============== ===========
(Footnotes on following page) F-29 41 NOBLE AFFILIATES, INC. AND SUBSIDIARIES NOTES TO THE PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS (1) Basis of Presentation The pro forma consolidated condensed statement of operations has been prepared by combining the consolidated statements of operations of Noble Affiliates, Inc. for the six months ended June 30, 1996 and the year ended December 31, 1995 with the consolidated statements of operations of EDC for the six months ended June 30, 1996 and the year ended December 31, 1995, respectively, assuming the EDC Acquisition and the financing thereof occurred at the beginning of the respective periods. The EDC Acquisition has been accounted for using the purchase method of accounting. Fully diluted earnings per share were computed using the "if converted method" assuming the outstanding convertible debt securities of Noble Affiliates, Inc. were converted into common stock at the beginning of the period. Such debt securities were antidilutive for the year ended December 31, 1995. (2) Non-Recurring Events Columbia Gas Transmission Corporation Settlement During 1995, both Noble Affiliates, Inc. and EDC settled their bankruptcy claims against Columbia Gas Transmission Corporation (Columbia) through the receipt of $48.9 million and $36.1 million, respectively. Noble Affiliates, Inc. and EDC recorded $39 million and $35 million as other income, respectively, related to these settlements during the year ended December 31, 1995. Impairment of Long-Lived Assets In March 1995, the Financial Accounting Standards Board issued Statement of Financial Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." Noble Affiliates, Inc. adopted SFAS No. 121 during 1995. Noble Affiliates recognized a $59.5 million SFAS No. 121 impairment for 1995. EDC evaluated the impact of SFAS No. 121 and determined that it would not have a significant impact on the financial condition or results of operations of EDC for 1995, based upon the current economic conditions. (3) Pro Forma Adjustments The unaudited pro forma consolidated condensed statement of operations reflects the following adjustments: (a) To record depreciation, depletion and amortization of the estimated net increase in the fair value of property and equipment acquired over historical cost related to such property and equipment and to provide for estimated additional restoration and abandonment costs related to oil and gas properties using the proved developed oil and gas reserves allocated property-by-property, estimated by Company engineers. Such fair values of assets and liabilities are based on estimates made at the time of the EDC Acquisition. (b) To reflect the estimated cost savings that the Company anticipates will be realized as a result of the EDC Acquisition, including those from facilities consolidation and elimination of employee costs of those EDC employees whose employment with the Company is expected to be terminated. (c) To reclassify certain costs and expenses (primarily employee costs) that Noble Affiliates, Inc. would classify as general and administrative costs that were included in EDC's financial statements as oil and gas exploration costs and expenses. F-30 42 (d) To reflect the net adjustment for the six months ended June 30, 1996 and the year ended December 31, 1995 of (i) the elimination of interest expense of $31.4 million for the year ended December 31, 1995 and $17 million for the six months ended June 30, 1996 associated with $312 million and $481 million of borrowings from affiliated companies at December 31, 1995 and June 30, 1996, respectively, which was contributed to EDC in connection with the EDC Acquisition, (ii) the addition of interest expense of $52 million for the year ended December 31, 1995 and $26 million for the six months ended June 30, 1996 associated with the $800 million borrowing under the line of credit and (iii) the reduction of interest expense of $3.4 million for the year ended December 31, 1995 and $1.7 million for the six months ended June 30, 1996 associated with the repayment of the $48 million borrowing under the line of credit in place during 1995 and the six months ended June 30, 1996. (e) To provide for income taxes at an assumed effective rate of 36% for all adjustments. F-31 43 NOBLE AFFILIATES, INC. AND SUBSIDIARIES PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET (UNAUDITED) (IN THOUSANDS)
AS OF JUNE 30, 1996(1) ------------------------------------------------------------------------------ ENERGY NOBLE DEVELOPMENT AFFILIATES, INC. CORPORATION ADJUSTMENTS PRO FORMA ------------------ ----------- ----------- --------- ASSETS: Current Assets $ 144,307 $ 73,563 $ (51,018)(a)(d) $ 166,852 Property, Plant and Equipment 885,462 604,795 130,989 (a) 1,621,246 Other 26,035 48,846 (6,825)(a) 68,056 ------------- ----------- ----------- ------------ $ 1,055,804 $ 727,204 $ 73,146 $ 1,856,154 ============= =========== =========== ============ LIABILITIES AND SHAREHOLDERS' EQUITY: Current Liabilities $ 113,324 $ 60,784 $ 74,322 (a) $ 248,430 Notes Payable - Affiliated Companies -- 487,818 (487,818)(c) -- Deferred Income Taxes 76,852 7,172 (4,422)(b) 79,602 Other Deferred Credits and Noncurrent Liabilities 38,286 4,425 6,069 (a) 48,780 Long-term Debt 377,010 -- 652,000 (d) 1,029,010 Shareholders' Equity 450,332 167,005 (167,005)(a) 450,332 ------------- ----------- ----------- ------------ Total Liabilities and Shareholders' Equity $ 1,055,804 $ 727,204 $ 73,146 $ 1,856,154 ============= =========== =========== ============
(Footnotes on following page) F-32 44 NOBLE AFFILIATES, INC. AND SUBSIDIARIES NOTES TO THE PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET (1) Basis of Presentation The pro forma consolidated condensed balance sheet has been prepared by combining the consolidated balance sheet of Noble Affiliates, Inc. with the consolidated balance sheet of EDC as of June 30, 1996 using the purchase method of accounting and assuming the EDC Acquisition and the financing thereof occurred on June 30, 1996. (2) Pro Forma Adjustments The unaudited pro forma consolidated condensed balance sheet reflects the following adjustments: (a) To reflect purchase accounting adjustments required to record the fair value of EDC's assets and liabilities. Such fair values are based on estimates made at the time of the EDC Acquisition. (b) To record the impact on deferred income taxes related to foreign operations resulting from fair market value adjustments described in these notes. For U.S. tax purposes, the Company elected to write up the assets acquired to their fair value. No such election for tax purposes is available in certain foreign countries. As a result, the adjustment reflects the estimated future tax effects of differences between financial statement and tax bases of assets and liabilities related to these foreign operations. (c) To record the net effect of the elimination of $488 million of borrowings from affiliated companies at June 30, 1996, which was contributed to EDC in connection with the EDC Acquisition. (d) To record the net effect of the $800 million borrowing under the Company's bank credit facility and the use of the proceeds therefrom to purchase all the outstanding common stock of EDC for approximately $768 million and to repay $48 million of outstanding indebtedness under a bank credit agreement at June 30, 1996. (e) To eliminate EDC equity accounts. F-33 45 Index to Exhibits 23.1 - Consent of Miller and Lents, Ltd. 23.2 - Consent of Deloitte & Touche LLP 99.1 - Summary Reserve Report on the estimated reserves of EDC as of July 1, 1996, prepared by Miller and Lents, Ltd., independent petroleum consultants EX-23.1 2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the use of our report to Energy Development Corporation dated September 27, 1996, and titled "Proved Reserves as of July 1, 1996," in the Noble Affiliates, Inc. Securities and Exchange Commission Form 8-K/A (No. 1) and to the references to Miller and Lents, Ltd. under the heading "Miller and Lents Reserve Report." MILLER AND LENTS, LTD. By:/s/ LARRY M. GRING ------------------------------- Larry M. Gring, Senior Vice President Houston, Texas September 27, 1996 EX-23.2 3 INDEPENDENT AUDITORS CONSENT 1 EXHIBIT 23.2 INDEPENDENT AUDITORS' CONSENT Noble Affiliates, Inc. Ardmore, Oklahoma We consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 2-64600, 2-81590, 33- 32692, 2-66654 and 33-54084) of Noble Affiliates, Inc. of our report on Energy Development Corporation dated February 16, 1996 (July 2, 1996 as to Notes 1 and 10), appearing in Form 8-K of Noble Affiliates, Inc., as amended. Deloitte & Touche LLP Houston, Texas September 27, 1996 EX-99.1 4 PROVED RESERVES 1 EXHIBIT 99.1 [Letterhead of Miller and Lents, Ltd.] September 27, 1996 Energy Development Corporation 1000 Louisiana, Suite 2900 Houston, Texas 77002 Re: PROVED RESERVES AS OF JULY 1, 1996 Gentlemen: As requested, we estimated the proved reserves attributed to Energy Development Corporation as of July 1, 1996. The results of our estimates using instructed prices and costs are shown below: TOTAL PROVED AND PROVED DEVELOPED RESERVES AS OF JULY 1, 1996
GAS (BCF) OIL (MMBBLS) ------------------------- --------------------- Total Proved Reserves: Domestic: Offshore Gulf of Mexico . . . . . . . . . . 182.1 8.2 Onshore . . . . . . . . . . . . . . . . . . 201.3 7.3 --------- --------- 383.4 15.5 International . . . . . . . . . . . . . . . . . . 40.6 24.9 --------- --------- 424.0 40.5 ========= ========= Total Proved Developed Reserves . . . . . . . . . . . . 347.6 28.8 ========= =========
The proved reserves of oil, condensate, and natural gas were estimated in accordance with the standards of the Society of Petroleum Engineers, Inc. as defined in the Appendix with the exception of using the instructed price schedules. The reserves reported herein were estimated from material balance, production performance, analogy, and volumetric calculations. Reserve estimates based on volumetric calculations and on analogy are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced. Prices for oil and gas were specified by Energy Development Corporation and were represented to be net of basis, Btu, and transportation charges. Operating costs and capital requirements were based on information provided by Energy Development Corporation. As you instructed, prices, operating costs and capital expenditures were not escalated. 2 Energy Development Corporation September 27, 1996 Page 2 The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report. In conducting these evaluations we relied upon cost data and other financial, operating engineering, and geological data from Energy Development Corporation, from the files of Miller and Lents, Ltd., and from public information sources. We relied upon Energy Development Corporation's representation of the ownership interests evaluated herein. No independent verifications of these matters were made by Miller and Lents, Ltd., as such verifications are beyond the scope of this assignment. The details of our investigations are in our files. Please call if you require additional information. Very truly yours, MILLER AND LENTS, LTD. By /s/ LARRY M GRING ---------------------------------- Larry M. Gring, Senior Vice President 3 Appendix Page 1 DEFINITIONS FOR OIL AND GAS RESERVES (1) RESERVES Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserve estimates are based on interpretation of geologic and/or engineering data available at the time of the estimate. Reserve estimates generally will be revised as reservoirs are produced, as additional geologic and/or engineering data become available, or as economic conditions change. Reserves do not include volumes of crude oil, condensate, natural gas, or natural gas liquids being held in inventory. If required for financial reporting or other special purposes, reserves may be reduced for on-site usage and/or processing losses. The ownership status of reserves may change due to the expiration of a production license or contract; when relevant to reserve assignment such changes should be identified for each reserve classification. Reserves may be attributed to either natural reservoir energy, or improved recovery methods. Improved recovery includes all methods for supplementing natural reservoir energy to increase ultimate recovery from a reservoir. Such methods include (1) pressure maintenance, (2) cycling, (3) waterflooding, (4) thermal methods, (5) chemical flooding, and (6) the use of miscible and immiscible displacement fluids. All reserve estimates involve some degree of uncertainty, depending chiefly on the amount and reliability of geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves in one of two classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be subclassified as probable or possible to denote progressively increasing uncertainty. PROVED RESERVES Proved reserves can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Proved reserves may be developed or undeveloped. In general, reserves are considered proved if commercial producibility of the reservoir is supported by actual production or formation tests. The term proved refers to the estimated volume of reserves and not just to the productivity of the well or reservoir. In certain instances, proved reserves may be assigned on the basis of electrical and other type logs and/or core analysis that indicate subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing, or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) the undrilled areas that can be reasonably judged as commercially productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the proved limit unless otherwise indicated by definitive engineering or performance data. Proved reserves must have facilities to process and transport those reserves to market that are operational at the time of the estimate, or there is a commitment or reasonable expectation to install such facilities in the future. - ------------------------ 1 Approved by the Board of Directors, Society of Petroleum Engineers (SPE), Inc. February 27, 1987. 4 Appendix Page 2 In general, proved undeveloped reserves are assigned to undrilled locations that satisfy the following conditions: (1) the locations are direct offsets to wells that have indicated commercial production in the objective formation, (2) it is reasonably certain that the locations are within the known proved productive limits of the objective formation, (3) the locations conform to existing well spacing regulations, if any, and (4) it is reasonably certain that the locations will be developed. Reserves for other undrilled locations are classified as proved undeveloped only in those cases where interpretations of data from wells indicate that the objective formation is laterally continuous and contains commercially recoverable hydrocarbons at locations beyond direct offsets. Reserves that can be produced through the application of established improved recovery methods are included in the proved classification when (1) successful testing by a pilot project or favorable production or pressure response of an installed program in that reservoir, or one in the immediate area with similar rock and fluid properties, provides support for the engineering analysis on which the project or program is based and (2) it is reasonably certain the project will proceed. Reserves to be recovered by improved recovery methods that have yet to be established through repeated commercially successful applications are included in the proved classification only (1) after a favorable production response from subject reservoir from either (a) a representative pilot or (b) an installed program, where the response provides support for the engineering analysis on which the project is based, and (2) it is reasonably certain the project will proceed. UNPROVED RESERVES Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. Estimates of unproved reserves may be made for internal planning or special evaluations, but are not routinely compiled. Unproved reserves are not to be added to proved reserves because of different levels of uncertainty. Unproved reserves may be divided into two subclassifications: PROBABLE and POSSIBLE. PROBABLE RESERVES. Probable reserves are less certain than proved reserves and can be estimated with a degree of certainty sufficient to indicate they are more likely to be recovered than not. In general, probable reserves may include (1) reserves anticipated to be proved by normal stepout drilling where subsurface control is inadequate to classify these reserves as proved; (2) reserves in formations that appear to be productive based on log characteristics but that lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area; (3) incremental reserves attributable to infill drilling that otherwise could be classified as proved but closer statutory spacing had not been approved at the time of the estimate; (4) reserves attributable to an improved recovery method which has been established by repeated commercially successful applications when a project or pilot is planned but not in operation and rock, fluid, and reservoir characteristics appear favorable for commercial application; (5) reserves in an area of a formation that has been proved productive in other areas of the field but subject area appears to be separated from the proved area by faulting and the geologic interpretation indicates subject area is structurally higher than the proved area; (6) reserves attributable to a successful workover, treatment, retreatment, change of equipment, or other mechanical procedure, where such procedure has not been proved successful in wells exhibiting similar behavior in analogous reservoirs; and (7) incremental reserves in a proved producing reservoir where an alternate interpretation of performance or volumetric data indicates significantly more reserves than can be classified as proved. 5 Appendix Page 3 POSSIBLE RESERVES. Possible reserves are less certain than probable reserves and can be estimated with a low degree of certainty, insufficient to indicate whether they are more likely to be recovered than not. In general, possible reserves may include (1) reserves suggested by structural and/or stratigraphic extrapolation beyond areas classified as probable, based on geologic and/or geophysical interpretation; (2) reserves in formations that appear to be hydrocarbon bearing based on logs or cores but that may not be productive at commercial rates; (3) incremental reserves attributable to infill drilling that are subject to technical uncertainty; (4) reserves attributable to an improved recovery method when a project or pilot is planned but not in operation and rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial; and (5) reserves in an area of a formation that has been proved productive in other areas of the field but subject area appears to be separated from the proved area by faulting and geologic interpretation indicates subject area is structurally lower than the proved area. RESERVE STATUS CATEGORIES Reserve status categories define the development and producing status of wells and/or reservoirs. DEVELOPED. Developed reserves are expected to be recovered from existing wells (including reserves behind pipe). Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be subcategorized as producing or non-producing. PRODUCING. Producing reserves are expected to be recovered from completion intervals open at the time of the estimate and producing. Improved recovery reserves are considered to be producing only after an improved recovery project is in operation. NONPRODUCING. Nonproducing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from completion intervals open at the time of the estimate, but which had not started producing, or were shut in for market conditions or pipeline connection, or were not capable of production for mechanical reasons, and the time when sales will start is uncertain. Behind-pipe reserves are expected to be recovered from zones behind casing in existing wells, which will require additional completion work or a future recompletion prior to the start of production. UNDEVELOPED. Undeveloped reserves are expected to be recovered: (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. -----END PRIVACY-ENHANCED MESSAGE-----