-----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, HZYLFPQuE/BD6viLYfEs6+eZCdb0DLTpaPbSyFC5OI7QMHj1h1vP3GJlNmnW5aww ILyyx7gH4BsMEc3UeM6yJw== 0000860713-97-000001.txt : 19970313 0000860713-97-000001.hdr.sgml : 19970313 ACCESSION NUMBER: 0000860713-97-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 15 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970312 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: SNYDER OIL CORP CENTRAL INDEX KEY: 0000860713 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752306158 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-10509 FILM NUMBER: 97555329 BUSINESS ADDRESS: STREET 1: 777 MAIN ST STE 2500 CITY: FORT WORTH STATE: TX ZIP: 76102 BUSINESS PHONE: 8173384043 MAIL ADDRESS: STREET 1: 777 MAIN STREET SUITE 2500 CITY: FORT WORTH STATE: TX ZIP: 76102 10-K 1 FORM 10-K FOR 12/31/96 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------------- Form 10-K (Mark one) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSACTION PERIOD FROM ________ TO ________ COMMISSION FILE NUMBER 1-10509 --------------------------- SNYDER OIL CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 75-2306158 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 777 MAIN STREET 76102 FORT WORTH, TEXAS (Zip Code) (Address of principal executive offices) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (817) 338-4043 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED - ----------------------------------------------- ------------------------------- COMMON STOCK NEW YORK STOCK EXCHANGE $6.00 CONVERTIBLE EXCHANGEABLE PREFERRED STOCK NEW YORK STOCK EXCHANGE 7% CONVERTIBLE SUBORDINATED NOTES NEW YORK STOCK EXCHANGE SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Aggregate market value of the common stock held by non-affiliates of the registrant as of March 10, 1997................................$482,325,221 Number of shares of common stock outstanding as of March 10, 1997....31,268,557 DOCUMENTS INCORPORATED BY REFERENCE Part III of this Report is incorporated by reference to the Registrant's definitive Proxy Statement relating to its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 1997. ================================================================================ SNYDER OIL CORPORATION ANNUAL REPORT ON FORM 10-K DECEMBER 31, 1996 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES GENERAL Snyder Oil Corporation (the "Company") is engaged in the development, acquisition and exploration of oil and gas properties primarily in the Rocky Mountain region of the United States and the Gulf of Mexico. The Company is also engaged in international exploration and production, primarily through affiliates. During 1996, consolidated revenues were $292.4 million and cash flow provided by operations approximated $101.7 million. At December 31, 1996, the Company's net proved reserves totaled 141.4 million barrels of oil equivalent ("BOE"), having a pretax present value at 10% based on constant prices ("Pretax PW 10% Value") of $1.2 billion. Approximately 71% of the reserves are natural gas. During 1996, the Company completed the repositioning begun in 1995 in response to dramatic deterioration of Rocky Mountain gas markets. During the year, the Company has concentrated investment in its growing core areas, primarily in the Gulf of Mexico, added industry partners in major gas development projects in the Rockies, disposed of nearly all remaining non-core properties and consolidated its Wattenberg properties with those of another major producer in the area to create Patina Oil & Gas Corporation ("Patina"), a separately-managed New York Stock Exchange listed company. The Company's investment in Patina should allow the Company to benefit from efficiencies arising out of the combination of the two largest producers in this field, while affording the Company a range of financial options in the future. The Company also made significant progress in strengthening its organization and administrative systems to ensure that it can deal with its expected growth in a more efficient and timely manner. As a result, the Company's domestic operations, excluding its investment in Patina, are focused on three areas, all of which have the potential to contribute significantly to future growth. These areas include: o The Gulf of Mexico, where 1997 efforts will be concentrated on further development in the Main Pass area, including construction of facilities for a major discovery and exploring the potential of other operated fields through drilling based on 3-D seismic. o The Rocky Mountain region in Wyoming, Colorado and Utah, where the Company expects to expand development of its three major gas projects in the Washakie, Deep Green River and Piceance Basins, begin exploratory drilling on two potentially significant gas projects in the Wind River and Big Horn Basins and further test the development potential of its oil projects in the Uinta Basin. o North Louisiana, where the 3-D seismic program to survey a portion of the Company's position of approximately 600,000 gross acres will be expanded. The Company expects to commence exploratory drilling in late 1997. The Company expects to increase its development and exploratory expenditures to $112 million for 1997, up from $51 million, excluding acquisitions, during 1996. Approximately $85 million is expected to be spent for development drilling programs, $19 million for expanded exploratory activity and $8 million for gas facilities and other activities. In total, the Company expects to drill 124 wells domestically, up from 85 wells in 1996. Approximately $48 million is targeted for continued development in the Gulf of Mexico, $38 million for expanded development of its major Rocky Mountain projects, and $2 million for additional leasing and seismic costs in North Louisiana. Internationally, the Company tendered its interest in its Australian affiliate for 16.2 million shares (approximately 9.6% of the outstanding shares) of Cairn Energy plc ("Cairn"), realizing a pretax gain of $65.5 million and 1 retaining a significant investment in a company positioned to become a major gas provider to the developing Indian Subcontinent. In Mongolia, where an affiliate holds over 10 million acres, two wells were drilled, one of which resulted in a second discovery. Ten wells were drilled in Russia, resulting in that venture increasing production to over 3,500 barrels per day. Near year end, the Company entered into an agreement with an international oil company that will fund the initial well on a prospective block offshore Thailand, while permitting the Company to retain a significant interest in the block. As the pace of international activity is accelerating, the Company is pursuing plans for an offering of its primary operating international subsidiary on a major international stock exchange to enhance the value of these investments to the Company's shareholders by establishing an independent valuation in an appropriate market. DOMESTIC OPERATIONS GENERAL. During 1996 the Company greatly increased the focus and balance of its domestic operations by investing capital primarily in its core operating areas and selling its remaining non-core assets. In Wattenberg, which represents over 50% of the Company's consolidated reserves, the Company formed Patina to combine the Company's properties with those of Gerrity Oil & Gas Corporation. Patina is a separately managed, New York Stock Exchange traded company that is 74% owned by the Company. Nearly all non-core properties were sold by the end of the year, with the Company's remaining domestic properties now concentrated in three operating divisions: o The Offshore Division holds interests in producing fields and prospective blocks in the Gulf of Mexico. As the result of three major acquisitions and a significant discovery near year end, this Division increased its proved reserves to 17.4 million BOE at year end (up from 3.6 million BOE at year end 1995), representing 12% of consolidated year end reserves. o The Rocky Mountain Division, which consists of two operating groups. The Major Gas Properties Group includes three major gas development programs, one mature gas field and two potentially large gas development projects on which initial drilling is expected to begin this year. The Rockies Group's properties include two large, mature non-operated oil fields in northern Wyoming and a potentially large oil development project in the Uinta Basin. This Division's properties, located in Wyoming, western Colorado and Utah, had proved reserves of 50.3 million BOE at year end (essentially unchanged from year end 1995), representing 36% of consolidated year end reserves. o The Southern Division, whose most significant remaining holding is over 300,000 gross mineral acres, with leases and lease options covering an equivalent position, in North Louisiana. A number of prospects have been identified through 2-D seismic and as a result of a 3-D seismic program during 1996, and it is likely that at least one well will be commenced by the end of 1997. The majority of the producing properties of the Southern Division, including its properties in the Austin Chalk Trend in Texas, were sold during 1996. Summary information at December 31, 1996 regarding the Company's major domestic projects is set forth in the following table. 2
PROVED RESERVE QUANTITIES NET ------------------------------------- PRETAX PW 10% VALUE PRODUCING UNDEVELOPED CRUDE OIL NATURAL OIL ---------------------- WELLS ACRES & LIQUIDS GAS EQUIVALENT AMOUNT PERCENT --------- ----------- --------- -------- ---------- ---------- ------- (MBbl) (MMcf) (MBOE) (000) Offshore Division Main Pass Area 15 8,553 1,570 86,238 15,943 $ 236,349 19% Other 26 0 851 3,717 1,470 8,488 1 Major Gas Properties Washakie (WY) 154 75,726 1,144 133,101 23,327 147,880 12 Piceance (CO) 70 44,355 118 32,170 5,479 39,045 3 Deep Green River (WY) 10 43,309 175 21,717 3,794 27,973 2 Wind River Basin (WY) 27 65,577 235 21,151 3,760 15,376 1 Big Horn Basin (WY) 0 80,550 0 0 0 0 0 Rockies Properties Northern Wyoming (WY) 932 787 12,083 531 12,172 76,938 6 Uinta Basin (UT) 127 79,899 1,152 3,861 1,795 9,042 1 Southern Division North Louisiana (LA) 96 (a) 318,090 (b) 40 2,715 492 6,615 1 ----- ------- ------ ------- ------- ---------- ---- Total Major Projects 1,457 716,846 17,368 305,201 68,232 567,706 46 Other 117 78,587 654 3,776 1,286 10,501 1 ----- ------- ------ ------- ------- ---------- ---- Total SOCO 1,574 795,433 18,022 308,977 69,518 578,207 47 Patina (CO) 3,602 (c) 141,713 22,475 296,659 71,918 648,797 53 ----- ------- ------ ------- ------- ---------- ---- Company consolidated 5,176 937,146 40,497 605,636 141,436 $1,227,004 100% ===== ======= ====== ======= ======= ========== ==== (a) Includes royalty interests in 82 wells. (b) Does not include 225,000 net acres under option. (c) Includes royalty interests in 195 wells.
SOCO OFFSHORE During 1996, the Company acquired the remaining stock interest in DelMar Petroleum, Inc., now named SOCO Offshore, Inc. With three large acquisitions of interests in its major properties and a major discovery, the Company has accomplished its goal of creating a significant presence in the Gulf of Mexico. The Offshore Division contributes a significant portion of the Company's reserves and production, with the potential to rapidly increase its contribution in the future as the major discovery comes on production and pipeline constraints are eliminated. The Company believes that many properties in the Gulf of Mexico have, and will continue to be, under-exploited and that, while offshore operations have greater risks than the Company's Rocky Mountain operations, the potential benefits and exposure to Gulf Coast markets will compliment the Company's Rocky Mountain activities and result in significant benefits to the Company. By year end, the Offshore Division had proved reserves of 2.4 million barrels of oil and 90 Bcf of gas (17.4 million BOE), up from 748,000 barrels of oil and 16.3 Bcf (3.5 million BOE) at year end 1995. Acquisitions accounted for 7.8 million BOE of this increase, and the discovery of the Ingrid Field in Main Pass Block 261 accounted for 6.3 million BOE. At year end the Offshore Division had interests in 41 (15.2 net) wells, 35 (14.1 net) of which were operated by the Company, and held interests in 103,000 (43,600 net) acres. December 1996 net production averaged 7,250 BOE per day, up from 1,100 BOE per day in December 1995. As the result of an acquisition at the end of the year, the Division's net daily production has reached 10,000 BOE per day. During 1997, the Gulf of Mexico will continue to be a major focus for the Company. Capital expenditures are expected to total $45 to $50 million, including $20.7 million to install platforms and related facilities, $8.9 3 million to drill three development wells and $16.2 million to drill eight exploratory wells, primarily on existing projects. In addition, the Company will continue its acquisition efforts in the area, including acquisitions of additional interest in its existing properties, and will continue to evaluate its existing properties for additional development or exploratory potential. The largest project, comprising the Pabst and Busch Fields in Main Pass Blocks 255 and 259, is in the Main Pass/Viosca Knoll area offshore Mississippi. The Offshore Division owns interests in 10 lease blocks in the project area and operates two platforms there. During 1996, additional interests in these Fields were acquired from three joint venture partners, increasing the Company's ownership from 12% to 60%. Four wells were successfully completed, and three successful workovers were completed. One dry hole was drilled. By year end, SOCO's proved reserves in these Fields totaled 52.1 Bcf of gas and 932,000 barrels of oil (9.6 million BOE), representing 55% of SOCO Offshore's total proved reserves. In 1997, the Offshore Division will continue to evaluate 3-D seismic data to evaluate these blocks for additional exploratory or development potential, with plans to commence two development wells during the year. During the year, the Offshore Division successfully generated and drilled two exploratory wells, resulting in the discovery of the Ingrid Field, on farm-in acreage in Main Pass Block 261, just west of the Pabst and Busch Fields. Initial proved reserves assigned to the Company's 50% interest in the Field were 34.1 Bcf of gas and 638,000 barrels of oil (6.3 million BOE) at year end. During 1997, the Company will begin installation of a platform and production facilities, with production initially expected to total 100 MMcf per day (37 MMcf per day net to the Company's interest) and to commence in early 1998. Full development of the Field, including four productive reservoirs already discovered, as well as additional prospects, is expected to require at least four additional wells. Two additional exploratory wells are expected to commence during 1997. Limited pipeline capacity has constrained production in the Main Pass/Viosca Knoll area. The Pabst and Busch Fields are capable of producing over 160 MMcf per day, but are currently producing approximately 100 MMcf per day due to pipeline constraints. The Company is negotiating with several pipelines to alleviate these constraints and to provide additional capacity to transport production from the Ingrid Field. Based on the proposals received, management expects to be able to secure arrangements that will increase capacity sufficiently to transport its production by late 1997 or early 1998. The Offshore Division also has interests in several other operated field areas in the Gulf of Mexico, with the Company's interest often exceeding 40%. During 1997, the Company will continue to evaluate these blocks for additional development or exploratory potential using recently acquired 3-D seismic data. Up to four exploratory wells could be drilled in 1997 to test these prospects, including one well that commenced drilling in February at High Island 208 offshore Texas. The Company also signed a farm-in agreement in late 1996 that will allow the Company to acquire a 50% interest in two suspended wells and a significant exploratory prospect in South Timbalier 231. A platform will be installed during the year to produce the suspended wells, and the initial exploratory well should commence in early 1998. MAJOR GAS PROJECTS During 1996, the Company, while maintaining a modest drilling schedule in view of low prices prevailing during the first ten months of the year, made significant strides in positioning its Rocky Mountain properties for long term growth. Significant interests were sold to industry partners in two major gas projects. The sales will allow expanded development of these Company-operated projects, while limiting the Company's capital requirements. In January 1997, the Company sold a one-half interest in two additional potentially large-scale gas projects on which initial drilling is scheduled for 1997. The Company also entered into an alliance with subsidiaries of Coastal Corporation ("Coastal") whereby the Company's gas production throughout most of the region will be pooled with that of other producers and marketed by Coastal Gas Marketing Company ("CGM") affording greater efficiency and the opportunity to share in the value associated with downstream sales of gas. As part of the venture, most of the Company's gas facilities were placed under common management with those of Coastal Field Services Company through the formation 4 of Great Divide Gas Services, LLC ("Great Divide"), allowing more efficient management and greater direction of future expansion. WASHAKIE BASIN. Since the mid-1980's, the Company's properties in the Barrel Springs Unit, the Blue Gap Field and the North Standard Draw area of the Washakie Basin in southern Wyoming, together with its gas gathering and transportation facilities there, have been one of its most significant assets. During 1996, the Company continued to develop Mesaverde sands in the Washakie Basin near its existing properties. Twelve wells were put on sales in 1996 at depths ranging from 8,000 to 11,500 feet, developing net proved reserves of 1.4 million BOE. Three wells were in progress at year end. Net production of gas, which accounts for approximately 95% of the reserves, during the year averaged 25.5 MMcf per day, as compared to average 1995 production of 22.9 MMcf per day. Proved reserves at year end totaled 1.1 million barrels of oil and 133.1 Bcf of gas, or 23.3 million BOE, as compared to 1.1 million barrels and 105 Bcf, or 18.6 million BOE, at the end of 1995. This increase in reserves is primarily attributable to increased gas prices at year end 1996 and extensions of the field. The Company expects to accelerate its activity in this area in 1997, with plans to drill 25 wells at costs ranging from $500,000 to $600,000 per well. The Company currently operates 128 wells in this area and holds hundreds of potential drilling locations, 66 of which were classified as proved undeveloped at year end 1996. The Company holds interests in approximately 97,000 gross (76,000 net) undeveloped acres in the Washakie Basin. DEEP GREEN RIVER. Through the year, the Company continued development of the fluvial Lance sands in the deep portion of the Green River Basin. The Company participated in eight wells during 1996, with two wells in progress at year end. Despite the sale of a 50% interest in the project to Amoco Production Company in the middle of the year, year end proved reserves totaled 175,000 barrels of oil and 21.7 Bcf of gas, or 3.8 million BOE, as compared to 107,000 barrels of oil and 15.9 Bcf of gas, or 2.8 million BOE, at year end 1995. This increase in reserves is primarily attributable to extensions of the field and increased gas prices at year end 1996. With 10 wells, six of which are operated by the Company, on sales at year end, net production averaged 832 BOE per day during 1996. The Company holds interests in approximately 95,000 gross (43,000 net) undeveloped acres in this project. At the end of 1996, proved undeveloped reserves were assigned to 17 locations. During 1996, the Company participated in a 51 square mile 3-D seismic survey that should allow high-grading of future drilling locations. The Company expects to participate in drilling up to 21 wells in 1997. Further expansion of drilling in this area is awaiting regulatory approval after preparation of an environmental impact statement, which is expected to be approved by mid-1997. Assuming the approval is granted, the Company expects to participate in drilling 25 to 30 wells per year after 1997. The primary objective of drilling is the stacked, fluvial sands of the Lance formation. PICEANCE BASIN. The Company operates the 53,000 acre Hunter Mesa Unit, the 9,000 acre Grass Mesa Unit and the 26,000 acre Divide Creek Unit in the southeast portion of the Piceance Basin. During the year, a 45% interest in this project was sold to Destec Energy Inc. At year end, the Company owned approximately 99,000 gross (44,000 net) undeveloped acres in this area. During 1996, the Company participated in 21 new wells to develop and further delineate the fields. Twenty-two wells (including two in progress at the beginning of the year) were put on sales, and one was in progress at year end. Net production averaged 9.7 MMcf per day in 1996, down from 1995 average production of 11.9 MMcf per day as a result of the sale of a 45% interest in the project. At year end 1996, there were 70 producing wells, 55 of which are operated by the Company. Proved reserves at year end were 32.2 Bcf of gas and 118,000 barrels of oil, or 5.5 million BOE, as compared with 42.6 Bcf and 145,300 barrels, or 7.2 million BOE, at year end 1995. The decrease in reserves is primarily the result of the sale to Destec, partially offset by extensions of the field and increased gas prices at year end 1996. Proved undeveloped reserves were assigned to 37 locations at year end 1996. During 1997, the Company plans to drill 23 wells to further develop the Company's acreage positions and evaluate the fields. An expanded development effort might be warranted if additional transportation arrangements can be made and gas prices stabilize at acceptable levels. The primary objective of drilling is the stacked, fluvial sands of the Mesaverde formation at depths of 4,500 to 8,500 feet. 5 WIND RIVER AND BIG HORN BASINS. The Riverton Dome Field, located in the Wind River Basin, produces gas primarily from the Frontier and Dakota tight sands at depths of 8,000 to 10,000 feet, with some sour crude oil production from the Tensleep and Phosphoria formations. At year end 1996, proved reserves, nearly all gas, totaled 3.8 million BOE. The Company operates 27 wells having net production of approximately 1,000 BOE per day. Production from this field is processed at a Company-owned plant. The Company has assembled approximately 65,000 (63,000 net) undeveloped acres in an area east of the Riverton Dome Field. In addition, the Company has obtained an option agreement to exploit oil and gas resources on approximately 33,000 net acres on Shoshone/Arapaho tribal lands toward the east and north of the Riverton Dome Field. In January 1997, the Company sold a 50% interest in a portion of this project, which targets various Cretaceous sands at depths of 8,500 to 12,500 feet, to Belco Oil & Gas. The Company expects to drill two wells during 1997, with the first well expected to commence in the second quarter. In the Big Horn Basin, northwest of the Worland Field, the Company has assembled approximately 120,000 gross (81,000 net) undeveloped acres. Belco also agreed to participate in this project, which also targets Cretaceous sands at depths of 9,500 to 12,000 feet. The first well was commenced in January 1997. GREAT DIVIDE. The Company owns over 225 miles of pipeline systems which transport gas from the Company's properties in the Washakie Basin and Piceance Basin. Effective January 1, 1997 the Company and Coastal Field Services Company, a subsidiary of Coastal, formed Great Divide to combine the operations of approximately 200 miles of pipelines owned by the Company with over 400 miles of Coastal systems in the Uinta, Washakie and Wind River Basins. Great Divide, which is 27% owned by the Company and will be jointly managed by its two shareholders, has combined assets of more than 600 miles of nonjurisdictional pipelines, connecting 650 natural gas wells producing approximately 165 MMcf per day. Great Divide will oversee the future expansion of gas pipelines and related facilities within six areas of mutual interest in Wyoming, Colorado and Utah. Also effective January 1, 1997, the Company entered into a gas sales agreement and gas marketing agreement with CGM, another subsidiary of Coastal, to pool the Company's and and other producers' gas supplies in the Rocky Mountain region. The initial supply pool is expected to exceed 100 MMcf per day, with over half the supply provided by the Company. The Company will sell its gas to CGM based on agreed market index prices and will share in the margin earned by CGM on downstream sales of the gas, based in part on the portion of the pool represented by Company gas. CGM and the Company will also evaluate commitments for firm transportation or longer term contracts, with commitments requiring joint agreement. The Company expects the joint venture to result in efficiencies in operating and managing their pipeline facilities, as well as creating greater focus for future expansion in the region. In addition, the Company hopes that the pooling of gas supplies and the expertise of Coastal, one of North America's largest gas marketers, will result in greater downstream marketing opportunities. Both the Company and Coastal intend to encourage other Rocky Mountain producers to join the joint venture, which would further increase the venture's potential to become a significant developer of facilities and marketer in the Rocky Mountain region. OTHER ROCKIES PROJECTS UINTA BASIN. In the Uinta Basin, the Company holds interests in approximately 115,000 gross (80,000 net) acres. During 1996, the Company participated in drilling only one non-operated well in the Basin as efforts were focused on acquiring and analyzing 3-D seismic data and implementing two pilot waterflood projects in its Green River oil projects. A pilot waterflood in the Leland Bench Field was commenced during the third quarter, with initial response expected to occur early in the second half of 1997. Depending on the response, development should begin in the second half of 1997. A second pilot project, in the Horseshoe Bend Field, is awaiting regulatory approval and should commence in mid-1997. The ultimate success of these projects will be influenced by the response of the pilot projects and the ability to select locations and enhance waterflood efforts through the use of 3-D seismic data. The projects are also 6 sensitive to oil prices. During the last half of 1996, oil prices, which had had historically been at a premium to West Texas Intermediate prices, deteriorated and now trade at a significant discount to such prices. As a result, 1997 activities have been reduced, with plans to drill only five wells during 1997. During 1996, net production from the Basin averaged 290 barrels of oil and approximately 1,255 Mcf of gas per day, as compared to 325 barrels and 1,377 Mcf per day during 1995. At year end, the Company had interests in 127 producing wells, 76 of which were operated by the Company. Proved reserves at year end were 1.2 million barrels of oil and 3.9 Bcf of gas, or 1.8 million BOE, as compared to 1.6 million barrels and 3.8 Bcf, or 2.2 million BOE, at the end of 1995. The decreases are primarily the result of production and sales during the year, as there was no significant development activity. Gas reserves increased primarily as the result of revisions resulting from higher prices prevailing at year end. NORTHERN WYOMING. The Company holds significant interests in two large, mature oil fields in Northern Wyoming, the Hamilton Dome and Salt Creek Fields. In late 1996, the Company unitized the Hamilton Dome Field to achieve common ownership of all producing horizons across the Field. Unitization resulted in an immediate net production increase to the Company of 140 barrels of oil per day and is expected to allow the current operator to decrease operating costs due to efficiencies and to proceed with an expansion of the existing waterflood and accelerate recompletions. At year end, proved reserves at these Fields totaled 12.2 million BOE, including 12.1 million barrels of oil and 531 MMcf of gas, up from 10.9 million BOE (10.8 million barrels and 455 MMcf) at the end of 1995. This increase was the result of upward revisions, primarily caused by higher product prices as well as increases resulting from the unitization of Hamilton Dome. Hamilton Dome produces sour crude oil primarily from the Tensleep, Madison and Phosphoria formations at depths of 2,500 to 5,500 feet. Salt Creek produces sweet crude oil from the Wall Creek formation at depths of 2,000 to 2,900 feet. NORTH LOUISIANA The Company owns over 300,000 gross mineral acres, with leases and lease option agreements covering an equivalent position, in north Louisiana and also owns overriding royalty interests in approximately 95 producing wells. The Company also has access to a database of more than 5,000 miles of 2-D seismic data and in 1996 joined with two partners to shoot a 48 square mile 3-D seismic survey covering a portion of its acreage. The results of this survey, which targeted potential significant reef structures in the Cotton Valley formation, were encouraging, and the partners have commenced a 110 square mile survey to the west of the previous survey. The Company has identified a number of reef prospects that will be imaged by the survey, which should be completed during the second half of 1997. These surveys are being shot at no cost to the Company, which will retain a 25% to 50% interest in the prospect areas. One well is expected to be commenced by the end of 1997. PATINA OIL & GAS CORPORATION During 1996 the Company implemented a significant restructuring of its Wattenberg Field assets by creating Patina. The Company formed Patina to hold its properties in the Wattenberg Field and to facilitate the acquisition of Gerrity Oil & Gas Corporation. In May 1996, the consolidation was completed. At year end, the Company owned 14 million, or 74%, of Patina's common shares. The Company has thus transformed its working interest in the Field to a controlling interest in the largest producer in the Field. At December 31, 1996, Patina held interests in over 3,600 wells in Wattenberg with net proved reserves of approximately 71.9 million BOE, approximately 70% of which were attributable to natural gas. Based on unescalated year end oil and gas prices, these reserves had a pretax PW 10% Value of $648.8 million. The Wattenberg Field is located approximately 35 miles north of Denver in the Denver-Julesburg Basin. One of the most attractive features of Wattenberg is that there are several productive formations. Three of the formations, the Codell, Niobrara and J-Sand, are "blanket" zones in the area of Patina's Wattenberg holdings, while others, such as the D-Sand, Dakota and the shallower Shannon and Sussex, are more localized. Drilling in Wattenberg is low risk 7 from the perspective of encountering hydrocarbons with better than 95% of the wells drilled being completed as producers. Consequently, the Field's economic attractiveness is primarily dependent on energy prices, the reservoir characteristics of the specific area of the Field being drilled and the operator's ability to minimize capital and operating costs. Over the past five years, Patina and its predecessors have drilled over 1,500 wells in Wattenberg. Given Patina's experience in drilling and completing wells of this type, combined with an operating base encompassing approximately 3,200 active wells, Patina believes it can drill and operate its oil and gas properties in the Field at a lower cost than its competitors. Furthermore, because virtually all of the wells in which it holds an interest lie within a 40 mile radius, Patina believes it has the potential to become one of the most efficient oil and gas producers in the United States. As of December 31, 1996, Patina had 728 proved undeveloped locations and 605 proved behind pipe recompletion opportunities. While this inventory provides the ability to expand development activities should drilling and completion technologies improve or the recent recovery in Rocky Mountain natural gas prices continues, a significant portion of Patina's proved undeveloped locations are projected to provide rates of return below the level judged attractive by its management based on projected commodity prices and reserve recoveries. During 1996, Patina focused on combining the operations of its predecessors, reducing costs and identifying attractive projects for further development. Only $8.5 million was spent on development and acquisitions, allowing Patina to use the bulk of its cash flow to reduce senior debt (to $94.5 million at year end as compared to $116.3 million at June 30, 1996) and repurchase securities. In 1997, Patina, at least for the present, expects to limit its capital expenditures on existing properties to approximately $14 million. As a result, management believes funds generated from operations should permit a continued paydown of debt, additional security repurchases or the pursuit of further consolidation or acquisition opportunities. As with all its investments and properties, the Company evaluates its position in Patina from time to time and assesses alternatives to increase value to the Company and its shareholders. A number of alternatives concerning Patina are available to the Company, including maintaining its investment, selling all or part of its investment, either in one transaction or gradually, distributing all or part of its investment to its shareholders or acquiring all of, or an increased interest in, Patina. Any decision, when made, will be made in light of strategic, financial and other factors deemed appropriate by management. INTERNATIONAL ACTIVITIES The Company's strategy internationally has been to develop a portfolio of projects that have the potential to make a major contribution to its production and reserves while limiting its financial exposure and mitigating political risk by seeking industry partners and investors to fund the majority of the required capital. A wholly-owned subsidiary of the Company, SOCO International, Inc. ("SOCO International"), is the holding company for all international operations. SOCO International, in turn, owns 90% of two subsidiaries, SOCO International Holdings, Inc. ("Holdings"), which owns shares of Cairn, as discussed below, and SOCO International Operations, Inc. ("Operations"), which holds all other international investments. In December 1996, Edward T. Story, the President of SOCO International and a Vice President and director of the Company, exercised an option to acquire the remaining 10% interest in these companies. As the pace of international activity is accelerating, the Company is pursuing plans for an offering of Operations on a major international stock exchange. The offering is intended to enhance the value of Operations' international projects to the Company's shareholders by establishing an independent valuation in an appropriate market. If the necessary agreements can be concluded, the offering could occur as early as the second quarter of 1997. CAIRN. In the fourth quarter of 1996, Cairn, a Scotland-based exploration and production company traded on the London Stock Exchange, agreed to acquire Command Petroleum Limited, an Australian company that was 32.6% 8 owned by SOCO International, in exchange for Cairn stock. As a result, SOCO International tendered its shares in Command for 16.2 million shares of Cairn (approximately 9.6% of the outstanding shares), realizing a pretax gain of $65.5 million. Cairn holds oil and gas interests in several countries, with a primary focus in the Bay of Bengal offshore Bangladesh, where it recently announced a major gas discovery. Cairn's position offshore Bangladesh, where it has identified additional prospects with significant exploratory potential, together with Command's interest in the Ravva Field offshore India, poise Cairn to make a major contribution to the development of oil and gas resources in the developing Indian Subcontinent. Although the potential of Cairn's major exploratory prospects, and thus the ultimate value of the Company's investment in Cairn, remains unknown, Cairn's prospects have been well received, resulting in the value of the Company's investment increasing from $95 million to over $130 million in February 1997. During February and March 1997, the Company sold 4.5 million shares of Cairn at an average price of $8.81 per share, realizing proceeds of $39.2 million, which was applied to repay SOCO International's debt to the Company. The remaining 11.7 million shares had a market value exceeding $100 million on March 6, 1997. The Company presently intends to remain a significant shareholder in Cairn, although it may elect to liquidate its holdings as Cairn's future potential is realized and market conditions warrant. RUSSIA. Permtex is a joint drilling venture formed in 1993 between Permneft, a Russian oil and gas company, and SOCO Perm Russia, Inc. ("SOCO Perm"), a subsidiary of SOCO International. The joint venture was formed to develop proven oil fields located in the Volga-Urals Basin of the Perm Region of Russia, approximately 800 miles east of Moscow. Permtex holds exploration and development rights to over 300,000 acres in the Volga-Urals Basin in a contract area containing four major and four minor fields, as well as other potential prospects. The Company estimates that the four major fields contained proved reserves of approximately 52 million barrels of oil at year end (8.6 million barrels net to the Company), with significant additional reserves expected to be ultimately recovered if waterflood projects are successfully implemented. The joint venture utilizes primarily Russian personnel and equipment and Western technology under joint Russian/American management. The major fields were delineated prior to the formation of the joint venture through 45 previously drilled wells. Twenty-one wells (10 of which were drilled in 1996) have been placed on production, and are currently producing from 3,500 to 4,000 barrels per day, up from a peak of 2,500 in 1995. During 1996, the joint venture produced approximately 776,000 barrels of oil, with all production (other than oil in transit) being exported and sold on the world market. Drilling activity has been slower than anticipated due to difficulties in securing drilling contracts on commercially reasonable terms. During 1997, the Company expects to drill 11 wells using Russian rigs. The Company has continued to fund its share of capital costs through sales of equity in SOCO Perm. In 1996, the Company concluded the sale of 15% of SOCO Perm's equity for $10 million. This sale decreased the Company's interest in SOCO Perm to approximately 35%. This sale required SOCO Perm to list its common shares on a securities exchange no later than 1998 or the investors have the right to require the Company to purchase their shares at a formula price. The proposed offering of Operations' shares is expected to satisfy this requirement. The commitment from the Overseas Private Investment Company, an agency of the United States Government, to provide up to $40 million in financing has been extended to mid-1997. MONGOLIA. SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"), a 42% owned affiliate of SOCO International, holds over 10 million acres covering the entire Tamtsag Basin of northeastern Mongolia. These concessions are located between the Hailar and Erlian Basins of China. The Company has also acquired 2,700 kilometers of seismic data in the Basin. During 1996, two exploratory wells were drilled and a second discovery was logged. Although production from the two discovery wells is not expected to be significant, SOCO Tamtsag's activities established the existence of productive sands across broad areas of the Basin. SOCO Tamtsag intends to drill four wells during 1997, including the SOTAMO 21-2, which began drilling in January. Although the prospective potential of the previously unexplored Tamtsag Basin has long been recognized, the lack of an outlet for production has prevented exploration there. In early 1995, SOCO Tamtsag entered into an agreement with China National United Oil Corporation ("CNUOC") under which CNUOC agreed to purchase crude oil produced by the venture at a mutually-agreed Mongolian/Chinese border point at world market prices, less $2 per barrel. 9 CNUOC is a joint venture between China National Petroleum Corporation and SINOCHEM, both state-owned entities. In early 1997, SOCO Tamtsag exported its first shipment of oil to China, successfully testing the marketing arrangements. THAILAND. In 1995, SOCO International acquired the 150,000 acre Block B4/32 concession in the Gulf of Thailand. During 1996, SOCO International was awarded Block B8/38. In late 1996, SOCO International reached an agreement with a Malaysian-based international oil company which will fund the drilling of an exploration well on Block B8/38. SOCO International will retain a 42.5% interest in Blocks B8/38 and B4/32. The initial well is scheduled to begin in the second quarter of 1997, and a second well on Block B8/38 may be drilled by the end of the year. VIETNAM. In late 1994, SOCO International signed a Memorandum of Understanding with Petrovietnam Exploration and Production regarding a joint exploration and development program on a certain concession offshore Vietnam. Since that time, negotiations regarding a joint venture structure have progressed considerably and have resulted in a formal bid being submitted for the offshore concession. The Company expects a decision on the award in mid-1997. PROVED RESERVES The following table sets forth estimated year end proved reserves for each of the years in the three year period ended December 31, 1996. Proved reserves of 8.6 million BOE with a PW 10% value of $25.8 million assigned to SOCO International projects in Russia are not included in the table.
DECEMBER 31, ------------------------------------------ 1994 1995 1996 -------- -------- -------- Crude oil and liquids (MBbl) Developed 26,104 21,637 31,869 Undeveloped 8,873 2,610 8,628 ------- ------- ------ Total 34,977 24,247 40,497 ======= ======= ====== Natural gas (MMcf) Developed 353,930 330,524 443,441 Undeveloped 157,321 65,194 162,195 ------- -------- ------- Total 511,251 395,718 605,636 ======= ======== ======= Total MBOE 120,186 90,200 141,436 ======= ======== =======
The following table sets forth pretax future net revenues from the production of proved reserves and the Pretax PW 10% Value of such revenues.
DECEMBER 31, 1996 -------------------------------------------------------- (In thousands) DEVELOPED UNDEVELOPED(a) TOTAL ---------- -------------- ---------- 1997 $ 248,683 $ (20,275) $ 228,408 1998 207,527 31,034 238,561 1999 164,789 38,767 203,556 Remainder 1,049,753 409,368 1,459,121 ---------- --------- ---------- Total $1,670,752 $458,894 $2,129,646 ========== ========= ========== Pretax PW 10% Value (b) $1,023,125 $203,879 $1,227,004 ========== ========= ========== (a) Net of estimated capital costs, including estimated costs of $34.1 million during 1997. (b) The after tax PW 10% value of proved reserves totaled $938.6 million at year end 1996.
10 The quantities and values shown in the preceding tables are based on prices in effect at December 31, 1996, averaging $24.47 per barrel of oil and $3.59 per Mcf of gas. Year end gas prices, although typically higher than prices prevailing through most of a calendar year, were at or near all time highs and significantly higher than prices prevailing throughout most of 1996. Prices for both oil and gas have fallen since year end, partially as the result of decreased demand associated with warm weather. Price reductions decrease reserve values by lowering the future net revenues attributable to the reserves and also by reducing the quantities of reserves that are recoverable on an economic basis. Price increases have the opposite effect. Any significant decline in prices of oil or gas could have a material adverse effect on the Company's financial condition and results of operations. Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. With respect to certain properties that historically have experienced seasonal curtailment, the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections. The present values shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is specified by the Securities and Exchange Commission ("SEC"), is not necessarily the most appropriate discount rate, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties operated by the Company, expenses exclude the Company's share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things, general and administrative costs and interest expense. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the above tables represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered. Netherland, Sewell & Associates, Inc. ("NSAI") and Ryder Scott Company Petroleum Engineers ("Ryder Scott"), independent petroleum consultants, prepared estimates of the Company's proved reserves which collectivelyrepresent 99% of Pretax PW 10% Value as of December 31, 1996. Approximately 85% was estimated independently by NSAI and 14% by Ryder Scott. No estimates of the Company's reserves comparable to those included herein have been included in reports to any federal agency other than the SEC. 11 PRODUCTION, REVENUE AND PRICE HISTORY The following table sets forth information regarding net production of crude oil and liquids and natural gas, revenues and expenses attributable to such production and to natural gas transportation, processing and marketing and certain price and cost information for each of the years in the five year period ended December 31, 1996.
1992 1993 1994 1995 1996 ---------- ---------- ---------- ---------- --------- (Dollars in thousands, except prices and per barrel equivalent information) Production Oil (MBbl) 1,776 3,451 4,366 4,278 3,884 Gas (MMcf) 23,090 35,080 43,809 53,227 55,840 MBOE (a) 5,989 9,297 11,668 13,149 13,191 Revenues Oil $ 33,512 $ 53,174 $ 64,625 $ 72,550 $ 79,201 Gas (b) 43,851 71,467 73,233 72,058 110,126 -------- -------- -------- -------- -------- Subtotal 77,363 124,641 137,858 144,608 189,327 Transportation, processing and marketing 38,611 94,839 107,247 38,256 17,655 Other 2,996 9,372 17,223 19,296 85,432 -------- -------- -------- -------- -------- Total $118,970 $228,852 $262,328 $202,160 $292,414 -------- -------- -------- -------- -------- Operating expenses Production $ 28,057 $ 41,401 $ 46,267 $ 52,486 $ 49,638 Transportation, processing and marketing 30,469 85,640 94,177 29,374 15,020 Exploration 1,515 2,960 6,505 8,033 4,232 -------- -------- -------- -------- -------- $ 60,041 $130,001 $146,949 $ 89,893 $ 68,890 -------- -------- -------- -------- -------- Direct operating margin $ 58,929 $ 98,851 $115,379 $112,267 $223,524 ======== ======== ======== ======== ======== Production data Average sales price (c) Oil (Bbl) $ 18.87 $ 15.41 $ 14.80 $ 16.96 $ 20.39 Gas (Mcf) (a) (b) 1.74 1.94 1.67 1.35 1.97 BOE (a) 12.92 13.41 11.82 11.00 14.35 Average production expense/BOE $ 4.68 $ 4.45 $ 3.97 $ 3.99 $ 3.76 Average production margin/BOE $ 8.24 $ 8.96 $ 7.85 $ 7.01 $ 10.59 (a) Gas production is converted to oil equivalents at the rate of 6 Mcf per barrel. Prior to 1993 certain high-priced gas was converted based on price equivalency. Average gas prices exclude this high priced gas production. (b) Sales of natural gas liquids are included in gas revenues. (c) The Company estimates that its composite net wellhead prices at December 31, 1996 were approximately $3.59 per Mcf of gas and $24.47 per barrel of oil.
12 PRODUCING WELLS The following table sets forth certain information at December 31, 1996 relating to the producing wells in which the Company owned a working interest. The Company also held royalty interests in 277 producing wells. Wells are classified as oil or gas wells according to their predominant production stream.
AVERAGE PRINCIPLE GROSS NET WORKING PRODUCT STREAM WELLS WELLS INTEREST ---------------------- ----- ----- -------- Crude oil and liquids 4,132 2,924 71% Natural gas 1,044 721 69% ----- ------ --- Total 5,176 3,645 70% ===== ===== ===
ACREAGE The following table sets forth certain information at December 31, 1996 relating to acreage held by the Company. Undeveloped acreage is acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well, including leasehold interests identified for development or exploratory drilling.
GROSS NET ---------- ---------- Domestic Developed (a) 359,000 236,000 Undeveloped (b) 1,322,000 937,000 --------- --------- Total 1,681,000 1,173,000 ========= ========= International Undeveloped Russia 306,000 53,000 Mongolia 10,796,000 4,534,000 Thailand 2,520,000 1,071,000 ---------- --------- Total 13,622,000 5,658,000 ========== ========= (a) Developed acreage is acreage assigned to producing wells. (b) The Company also held 225,000 net undeveloped acres under option in North Louisiana.
13 DRILLING RESULTS The following table sets forth information with respect to domestic wells drilled during the past three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.
1994 1995 1996 ------ ------ ----- Development wells Productive Gross 466.0 223.0 69.0 Net 390.6 133.1 38.9 Dry Gross 12.0 5.0 2.0 Net 11.1 3.8 .5 Exploratory wells Productive Gross - - 3.0 Net - - .5 Dry Gross 13.0 - 2.0 Net 10.5 - 1.6
On December 31, 1996, the Company had 17 gross (13.1 net) development wells and 2 gross (1.0 net) exploratory wells in progress. Between year end and February 28, 1997, the Company spudded 19 wells. At that date, 18 gross (14.7 net) wells, including wells in progress at year end, had been completed, and 14 gross (9.8 net) development wells were in progress. CUSTOMERS AND MARKETING The Company's oil and gas production is principally sold to end users, marketers and other purchasers having access to pipeline facilities near its properties. Where there is no access to pipelines, crude oil is trucked to storage facilities. In 1994 and 1995, Amoco Production Company accounted for approximately 11% and 10% of revenues, respectively. In 1996, Pan Energy, which purchases a significant portion of Patina's gas production, accounted for approximately 11% of revenues. The marketing of oil and gas by the Company can be affected by a number of factors that are beyond its control and whose future effect cannot be accurately predicted. The Company does not believe, however, that the loss of any of its customers would have a material adverse effect on its operations. The Company's gas marketing effort is currently exclusively focused on the sale of production from its properties. Third party gas marketing was discontinued in 1994. During 1996, the volume of the Company's gas production marketed by the Company averaged approximately 136 MMcf per day. Market conditions in 1995 and early 1996 highlighted the need to create new market outlets for Rocky Mountain gas. As part of a program to diversify the markets for its gas production, the Company has pursued transactions that effectively transfer the price that it receives for a portion of its Rocky Mountain gas to the Gulf Coast market. See Note 2 to the Consolidated Financial Statements of the Company. As of year end 1996, 61% of the Company's production was sold under arrangements that are responsive to Rocky Mountain market conditions, and 39% was sold in the Gulf Coast market. As described on page 6 under "Domestic Operations - Major Gas Properties - Great Divide," effective January 1, 1997, the Company's Rocky Mountain gas production (excluding Patina's production) is being pooled with that of other producers and marketed by a subsidiary of Coastal. By pooling gas supplies and using Coastal's expertise, this venture is expected to increase opportunities for downstream marketing of the Company's Rocky Mountain gas. 14 COMPETITION The oil and gas industry is highly competitive in all its phases. Competition is particularly intense with respect to the acquisition of producing properties. There is also competition for the acquisition of oil and gas leases, the marketing of production, in the hiring of experienced personnel and from other industries in supplying alternative sources of energy. Competitors in acquisitions, exploration, development, marketing and production include the major oil companies in addition to numerous independent oil companies, individual proprietors, drilling and acquisition programs and others. Many of these competitors possess financial and personnel resources substantially in excess of those available to the Company. Such competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties than the financial or personnel resources of the Company permit. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable producing properties and prospects for future exploration and development. TITLE TO PROPERTIES Title to the properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, to liens incident to operating agreements and for current taxes not yet due and other comparatively minor encumbrances. As is customary in the oil and gas industry, only a perfunctory investigation as to ownership is conducted at the time undeveloped properties believed to be suitable for drilling are acquired. Prior to the commencement of drilling on a tract, a detailed title examination is conducted and curative work is performed with respect to known significant title defects. REGULATION REGULATION OF DRILLING AND PRODUCTION. The Company's operations are affected by political developments and federal and state laws and regulations. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic and other reasons. Numerous departments and agencies, federal, state, local and Indian, issue rules and regulations binding on the oil and gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases SOCO's cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects. A substantial portion of the Company's oil and gas leases in the Gulf of Mexico and in the Rocky Mountain area were granted by the U.S. Government and are administered by two federal agencies, the Bureau of Land Management ("BLM") and the Minerals Management Service ("MMS"). These leases are issued through competitive bidding, contain relatively standard terms and require compliance with detailed BLM and MMS regulations and orders (which are subject to change by the BLM and MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans before commencement of operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the BLM or MMS prior to the commencement of onshore or offshore drilling. State regulatory authorities have also established rules and regulations requiring permits for drilling, reclamation and plugging bonds and reports concerning operations, among other matters. Many states also have statutes and regulations governing a number of environmental and conservation matters. Colorado, where all Patina's properties and a portion of the Company's properties are located, amended its statute concerning oil and gas development in 1994 to provide the state's Oil and Gas Conservation Commission with additional authority to regulate oil and gas activities to protect public health, safety and welfare, as well as the environment. Several rulemakings pursuant to these statutory changes have, or will be, undertaken by the Commission to revise the regulation of groundwater protection, soil protection and site reclamation and financial assurance for industry obligations in these areas. To date, these rule changes have not adversely affected oil and gas operations of either the Company or Patina, as the Commission is required to enact cost-effective and technically feasible regulations. However, there can be no assurance that, in the aggregate, these regulatory developments, or developments in other states, will not increase the cost of conducting oil and gas operations. 15 In the past, the federal government has regulated the prices at which oil and gas could be sold. Prices of oil and gas sold by the Company are not currently regulated. In recent years, the Federal Energy Regulatory Commission ("FERC") has taken significant steps to increase competition in the sale, purchase, storage and transportation of natural gas. Under these orders, FERC has caused pipelines to open up access to transportation, essentially eliminating pipelines from the role of natural gas merchant and "unbundled" transportation services so that a buyer can purchase just those services it needs. FERC's regulatory programs generally allow more accurate and timely price signals from the consumer to the producer and, on the whole, have helped gas become more responsive to changing market conditions. To date, the Company believes it has not experienced any material adverse effect as the result of these programs. Nonetheless, increased competition in gas markets can and does add to price volatility and inter-fuel competition, which increases the pressure on the Company to manage its exposure to changing conditions and position itself to take advantage of changing market forces. ENVIRONMENTAL REGULATIONS. The operations of the Company are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, prohibit drilling activities on certain lands lying within wilderness and other protected areas and impose remediation obligations and substantial liabilities for pollution resulting from drilling operations. Such laws and regulations also restrict air or other pollution and disposal of wastes resulting from the operation of gas processing plants, pipeline systems and other facilities owned directly or indirectly by the Company. Drilling and other projects on federal leases may also require preparation of an environmental assessment or environmental impact statement, which could delay the commencement of operations and could limit the extent to which the leases may be developed. The Company currently owns or leases numerous properties that have been used for many years for natural gas and crude oil production. Although the Company believes that it and other previous owners have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company. In connection with its most significant acquisitions, the Company has performed environmental assessments and found no material environmental noncompliance or clean-up liabilities requiring action in the near or intermediate future, although some matters identified in the environmental assessments are subject to ongoing review. The Company has assumed responsibility for some of the matters identified. Some of the Company's properties, particularly larger units that have been in operation for several decades, may require significant costs for reclamation and restoration when they are divested or when operations eventually cease. Environmental assessments have not been performed on all of the Company's properties. To date, expenditures for environmental control facilities and for remediation have not been significant to the Company, and the Company does not expect that, under current regulations, future expenditures will have a material adverse impact on the Company. Under the Oil Pollution Act of 1990 ("OPA"), owners and operators of onshore facilities and pipelines and lessees or permittees of an area in which an offshore facility is located ("Responsible Parties") are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into United States waters. These damages include natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350 million in the case of onshore facilities and $75 million plus removal costs in the case of offshore facilities, except that no limits apply if the discharge was caused by gross negligence or wilful misconduct, or by the violation of an applicable federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor. In addition, OPA requires certain vessels and offshore facilities to provide evidence of financial responsibility. During 1996, OPA was amended to reduce the required level of financial responsibility from $150 million to $35 million for offshore facilities and $10 million for facilities located in state waters. OPA also requires offshore facilities to prepare facility response plans, which the Company has done, for responding to a "worst case discharge" of oil. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties. 16 States in which the Company operates have also adopted regulations to implement the Federal Clean Air Act. These new regulations are not expected to have a significant impact on the Company or its operations. In the longer term, regulations under the Federal Clean Air Act may increase the number and type of the Company's facilities that require permits, which could increase the Company's cost of operations and restrict its activities in certain areas. OFFICERS Listed below are the officers and a summary of their recent business experience. NAME POSITION John C. Snyder Chairman and Director Charles A. Brown Senior Vice President-Rocky Mountain Division Steven M. Burr Vice President-Engineering and Planning Peter C. Forbes Vice President-Offshore Peter E. Lorenzen Vice President-General Counsel H. Richard Pate Vice President-Major Gas Projects David M. Posner Vice President-Gas Management James H. Shonsey Vice President-Finance Edward T. Story Vice President-International and Director Rodney L. Waller Vice President-Special Projects Richard A. Wollin Vice President-Southern Division and Acquisitions JOHN C. SNYDER (55), a director and Chairman, founded a predecessor of the Company in 1978. From 1973 to 1977, Mr. Snyder was an independent oil operator in Texas and Oklahoma. Previously, he was a director and the Executive Vice President of May Petroleum, Inc. where he served from 1971 to 1973. Mr. Snyder was the first president of Canadian-American Resources Fund, Inc., which he founded in 1969. From 1964 to 1966, Mr. Snyder was employed by Humble Oil and Refining Company (currently Exxon Co., USA) as a petroleum engineer. Mr. Snyder received his Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma and his Masters Degree in Business Administration from the Harvard University Graduate School of Business Administration. Mr. Snyder also serves as a director of Patina. CHARLES A. BROWN (50), Senior Vice President - Rocky Mountain Division, joined the Company in 1987. He was a petroleum engineering consultant from 1986 to 1987. He served as President of CBW Services, Inc., a petroleum engineering consulting firm, from 1979 to 1986 and was employed by Kansas Nebraska Natural Gas Company from 1971 to 1979 and Amerada Hess Corporation from 1969 to 1971. Mr. Brown received his Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines. STEVEN M. BURR (40), Vice President - Engineering and Planning, joined the Company in 1987. From 1982 to 1987, he was a Vice President with the petroleum engineering consulting firm of Netherland, Sewell & Associates, Inc. From 1978 to 1982, Mr. Burr was employed by Exxon Company, USA in the Production Department. Mr. Burr received his Bachelor of Science Degree in Civil Engineering from Tulane University. PETER C. FORBES (51), Vice President - Gulf of Mexico, who was appointed to that position in 1996, joined the Company as Executive Vice President of SOCO Offshore, Inc., the Company's Gulf Coast subsidiary, in July 1995 and has been President of that company since July 1996. From 1994 to 1995, he was President and Chief Executive Officer of SD Resources, Inc., the general partner of Sand Dollar Resources L.P., a partnership with Enron Gas Services Corp., a subsidiary of Enron Corp. From 1992 to 1993, Mr. Forbes was Vice President in charge of the oil and gas property acquisition unit of Enron Gas Services Corp. From 1988 to 1992, he was President and a director of American Exploration Company. Prior thereto, Mr. Forbes was Vice President, Finance of Browning-Ferris Industries, Inc. during 1988 and Senior Vice President and Chief Financial Officer of Zapata Corporation from 1985 to 1987. He served in several positions, including Vice President and Treasurer, at Texas Eastern Transmission Corporation from 1975 to 1985. Mr. Forbes received his Bachelor of Arts Degree from Edinburgh University and is a Scottish Chartered Accountant. 17 PETER E. LORENZEN (47), Vice President - General Counsel and Secretary, joined the Company in 1991. From 1983 through 1991, he was a shareholder in the Dallas law firm of Johnson & Gibbs, P.C. Prior to that, Mr. Lorenzen was an associate with Cravath, Swaine & Moore. Mr. Lorenzen received his law degree from New York University School of Law and his Bachelor of Arts Degree from The Johns Hopkins University. H. RICHARD PATE (43), Vice President - held various positions with Mitchell Energy Corporation, including Region Engineer and Production Manager. He was employed by Champlin Petroleum Company from 1979 to 1981 and Atlantic Richfield Corporation from 1975 to 1979. Mr. Pate received his Bachelor of Science Degree in Chemical Engineering from the University of Wyoming. DAVID M. POSNER (43), Vice President - Gas Management Group, joined the Company in 1991. From 1980 to 1991 he held various positions with Ladd Petroleum Corporation (a subsidiary of the General Electric Company) including Vice President of Gas Gathering, Processing and Marketing. Mr. Posner received his Bachelor of Arts degree from Brown University and his Master of Science in Mineral Economics from the Colorado School of Mines. JAMES H. SHONSEY (45), Vice President - Finance, joined the Company in 1991. From 1987 to 1991, Mr. Shonsey served in various capacities including Director of Operations Accounting for Apache Corporation. From 1976 to 1987 he held various positions with Deloitte & Touche, Quantum Resources Corporation, Flare Energy Corporation and Mizel Petro Resources, Inc. Mr. Shonsey received his Bachelor of Science Degree in Accounting from Regis University and his Master of Science Degree in Accounting from the University of Denver. EDWARD T. STORY (53), a director and Vice President - International of the Company and President of SOCO International, Inc., joined the Company in 1991. Mr. Story became a director of the Company in February 1996. From 1990 to 1991, Mr. Story was Chairman of the Board of a jointly-owned Thai/US company, Thaitex Petroleum Company. Mr. Story was co-founder, Vice Chairman of the Board and Chief Financial Officer of Conquest Exploration Company from 1981 to 1990. He served as Vice President, Finance and Chief Financial Officer of Superior Oil Company from 1979 to 1981. Mr. Story held the positions of Exploration and Production Controller and Refining Controller with Exxon USA from 1975 to 1979. He held various positions in Esso Standard's international companies from 1966 to 1975. Mr. Story received a Bachelor of Science Degree in Accounting from Trinity University, San Antonio, Texas and a Masters of Business Administration from the University of Texas in Austin. Mr. Story serves as a director of First BanksAmerica, Inc., a bank holding company, Hi/Lo Automotive, Inc., a distributor of automobile parts, Hallwood Realty Corporation, the general partner of Hallwood Realty Partners, L.P., an American Stock Exchange-listed real estate limited partnership, and Seaunion Holdings Limited, an oil and gas company listed on the Hong Kong Stock Exchange. RODNEY L. WALLER (47), Vice President - Special Projects, joined the Company in 1977. Previously, Mr. Waller was employed by Arthur Andersen & Co. Mr. Waller received his Bachelor of Arts Degree from Harding University. RICHARD A. WOLLIN (44), Vice President - Southern Division and Acquisitions, joined the Company in 1990. From 1983 to 1989, Mr. Wollin served in various management capacities including Executive Vice President of Quinoco Petroleum, Inc. with primary responsibility for acquisition, divestiture and corporate finance activities. From 1976 to 1983, he was employed in various capacities for The St. Paul Companies, Inc., including Senior Vice President of St. Paul Oil & Gas Corp. Mr. Wollin received his Bachelor of Science Degree from St. Olaf College and his law degree from the University of Minnesota Law School. Mr. Wollin is a member of the Minnesota Bar Association. FORWARD-LOOKING INFORMATION Certain information included and incorporated by reference in this Annual Report, and other materials filed or to be filed by the Company with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Company) contain or will contain or include, 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. Such forward-looking statements may be or may concern, among other 18 things, capital expenditures, drilling activity, acquisitions and dispositions, and conditions and transactions related thereto, development or exploratory activities, cost savings efforts, production activities and volumes, hydrocarbon reserves, hydrocarbon prices, hedging activities and the results thereof, financing plans, liquidity, regulatory matters, competition and the Company's ability to realize efficiencies related to certain transactions or organizational changes. All forward-looking information is based upon management's current plans, expectations, estimates and assumptions and is subject to a number of uncertainties and risks that could significantly affect current plans, anticipated actions, the timing of such actions and the Company's financial condition and results of operations. The risks and uncertainties associated with such forward-looking statements include generally the volatility of hydrocarbon prices and hydrocarbon-based financial derivatives prices; basis risk and counterparty credit risk in executing hydrocarbon price risk management activities; economic, political, judicial and regulatory developments; developments in financial markets, both domestic and foreign; competition in the industry, as well as competition from other sources of energy; the economics of producing certain reserves; hydrocarbon demand and supply; the ability to find or acquire and develop reserves of natural gas and crude oil; and the actions of customers and competitors. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in any forward-looking statements made by or on behalf of the Company. ITEM 3. LEGAL PROCEEDINGS In August 1995, the Company was sued in the United States District Court of Colorado by seven plaintiffs purporting to represent all persons who, at any time since January 1, 1960, have had agreements providing for royalties from gas production in Colorado to be paid by the Company under a number of various lease provisions. In January 1997, the judge ordered that the class not be certified. All remaining liability under this suit was assumed by Patina upon its formation. In January 1996, GOG was also sued in a similar but separate class action filed in stated court. In both suits, the plaintiffs allege that unspecified "post-production" costs incurred prior to calculating royalty payments were deducted in breach of the relevant lease provisions and that this fact was fraudulently concealed. The plaintiffs seek unspecified compensatory and punitive damages and a declaratory judgment prohibiting deduction of post-production costs prior to calculating royalties paid to the class. The Company believes that calculations of royalties by it and GOG are and have been proper under the relevant lease provisions, and intends to defend these and any similar suits vigorously. In September 1996, the Company and other interest owners in a lease in southern Texas were sued by the royalty owners in Texas state court in Brooks County, Texas. The Company's working interest in the lease is approximately 20%. The complaint alleges, among other things, that the defendants have failed to pay proper royalties under the lease and have breached their duties to reasonably develop the lease. The plaintiffs also claim damages for fraud and trespass, and demand actual and punitive damages. Although the complaint does not specify the amount of damages claimed, an earlier letter from plaintiffs claimed damages in excess of $50 million. The Company and the other interest owners have filed an answer denying the claims and intend to contest the suit vigorously. At this time, the Company is unable to estimate the range of potential loss, if any, from the foregoing uncertainties. However, the Company believes their resolution should not have a material adverse effect upon the Company's financial position, although an unfavorable outcome in any reporting period could have a material impact on the Company's results of operations for that period. The Company and its subsidiaries and affiliates are named defendants in lawsuits and involved from time to time in governmental proceedings, all arising in the ordinary course of business. Although the outcome of these lawsuits and proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted for a vote of security holders during the fourth quarter of 1996. 19 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS The Company's stock is listed on the New York Stock Exchange and trade under the symbol "SNY". The following table sets forth, for 1995 and 1996, the high and low sales prices for the Company's securities for New York Stock Exchange composite transactions, as reported by THE WALL STREET JOURNAL.
1995 1996 ----------------------- ----------------------- HIGH LOW HIGH LOW ------- ------- ------- ------- First Quarter $15-1/4 $13-1/2 $12-1/8 $ 7-1/4 Second Quarter 15-3/8 11-7/8 10-1/4 7-5/8 Third Quarter 14 10-3/4 12 9-3/8 Fourth Quarter 12-3/4 10 17-3/4 11-3/4
On March 10, 1997, the closing price of the common stock was $17-3/8. Quarterly dividends have been paid at the rate of $.065 per share during 1995 and 1996. For federal income tax purposes, 100% of common dividends paid during 1995 and 1996 were a non-taxable return of capital. The Company currently expects that dividend payments in 1997 will be taxable for federal income tax purposes. Shares of common stock receive dividends as, if and when declared by the Board of Directors. The amount of future dividends will depend on debt service requirements, dividend requirements on preferred stock, capital expenditures and other factors. On December 31, 1996, there were approximately 2,600 holders of record of the common stock and 31.2 million shares outstanding. 20 ITEM 6. SELECTED FINANCIAL DATA The following table presents selected financial and operating information for each of the years in the five year period ended December 31, 1996. Share and per share amounts refer to common shares. The following information should be read in conjunction with the consolidated financial statements presented elsewhere herein.
(In thousands, except per share data) As of or for the Year Ended December 31, ------------------------------------------------------------ 1992 1993 1994 1995 1996 --------- --------- --------- --------- --------- INCOME STATEMENT Revenues $ 118,970 $ 228,852 $ 262,328 $ 202,160 $ 292,414 Income (loss) before extraordinary items 14,597 22,538 12,372 (39,831) 62,950 Per share .43 .58 .07 (1.53) 1.81 Net income (loss) 14,597 19,545 12,372 (39,831) 62,950 Per share .43 .45 .07 (1.53) 1.81 Dividends per share .25 (a) .22 .25 .26 .26 Average shares outstanding 22,722 23,096 23,704 30,186 31,308 CASH FLOW Net cash provided by operations $ 48,339 $ 68,728 $ 86,397 $ 69,121 $ 101,730 Net cash realized (used) by investing (73,645) (207,933) (245,503) 32,421 (62,356) Net cash realized (used) by financing 21,079 129,633 169,926 (96,012) (38,715) BALANCE SHEET Working capital $ 7,619 $ 491 $ 708 $ 5,842 $ 9,168 Oil and gas properties, net 241,804 316,406 472,239 435,217 635,387 Total assets 331,638 453,301 673,259 555,493 879,459 Senior debt 96,568 114,952 234,857 150,001 188,231 (b) Subordinated notes 18,750 - 83,650 84,058 183,842 (c) Stockholders' equity 168,866 274,734 274,086 235,368 294,668 (a) Due to revised timing, five payments were made at a quarterly rate of $.05 in 1992. (b) Includes $93.7 million of SOCO senior debt and $94.5 million of Patina senior debt. (c) Includes $80.7 million of SOCO convertible subordinated notes and $103.1 million of Patina subordinated notes.
The following table sets forth unaudited summary financial results on a quarterly basis for the two most recent years.
(In thousands, except per share data) 1995 ---------------------------------------------- FIRST SECOND THIRD FOURTH ------- ------- -------- -------- Revenues $53,017 $57,142 $50,839 $41,162 Depletion, depreciation and amortization and property impairments 19,986 20,675 22,540 40,589 (a) Gross profit (deficit) 8,901 12,564 1,672 (14,660) Net income (loss) (5,981) 525 (9,606) (24,769) Per share (.25) (.03) (.37) (.88) (In thousands, except per share data) 1996 ---------------------------------------------- FIRST SECOND THIRD FOURTH ------- ------- ------- --------- Revenues $41,719 $56,768 $62,475 $131,452 Depletion, depreciation and amortization and property impairments 16,771 22,745 24,673 23,111 Gross profit 9,979 2,217 18,746 89,801 Net income (loss) 1,777 (9,983) 5,560 65,596 Per share .01 (.37) .13 2.06 (a) Includes $24.1 million of property impairments.
21 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS COMPARISON OF 1996 RESULTS TO 1995. Total revenues for 1996 were $292.4 million, a $90.3 million increase from 1995. The increase is in large part due to a $67.2 million increase in gains on sales of investments which is primarily due to a $65.5 million gain recognized in the fourth quarter related to an exchange of the Company's stock held in Command Petroleum Limited ("Command"), an Australian affiliate, for stock in Cairn Energy plc ("Cairn"), a United Kingdom based company. An increase in oil and gas sales of $44.7 million was also experienced in 1996 as a result of a 31% rise in the price received per barrel of oil equivalent ("BOE") while production remained relatively stable compared to 1995. Natural gas prices rebounded in 1996 to $1.97 per Mcf from $1.35 per Mcf in 1995, a 46% increase. Oil prices improved 20% to average $20.39 per barrel during 1996. Partially offsetting these increases was a decrease in gas transportation, processing and marketing revenues of $20.6 million primarily as a result of the sale of the Company's Wattenberg gas facilities in 1995. Net income for 1996 was $63.0 million, compared to a net loss in 1995 of $39.8 million. The 1996 income was boosted by the net effect of the Command transaction ($57.2 million after minority interest expense and deferred tax expense). However, the Company also recorded a noncash charge of $15.5 million in the second quarter related to the contribution of the Company's Wattenberg oil and gas properties to a newly formed public company, Patina Oil and Gas Corporation ("Patina"), in return for a 70% stake in Patina. The 1995 loss was primarily due to $27.4 million in noncash property impairment charges and almost $11 million in combined losses resulting from a litigation settlement, losses on marketable securities, as well as severance and restructuring costs. Absent these special non-recurring items, there was an increase in net income from 1995 to 1996 of approximately $23 million. This increase can be attributed primarily to the 31% increase in average price received per BOE which increased revenues $44.7 million offset partially by a decrease in gas management margin of $6.2 million and an increase in depreciation, depletion and amortization expense of $8.2 million. Revenues from production operations, less direct operating expenses, for 1996 were $139.7 million, an increase of 52% from 1995 net revenue. Average daily production during 1996 was 36,040 BOE, almost exactly what it was in 1995 (36,024 BOE). However, the average product price received increased by 31% to $14.35 per BOE. Production remaining relatively constant from 1995 to 1996 can be attributed to additional interests acquired in four Gulf of Mexico acquisitions in late 1995 and during 1996 and the properties acquired in the Patina transaction offset by decreased production related to numerous sales of noncore properties which have occurred over the past two years and the reduction of development drilling. The Company focused the last two years on divesting of marginal assets and acquiring strategic assets that allow for future growth of the Company. This process is substantially complete and the Company is now in position for growth. The Company expects to increase its development schedule in 1997 which, along with two acquisitions in the Gulf of Mexico in the fourth quarter 1996, should result in an increase in production during 1997. Total operating expenses for 1996 decreased by $2.8 million in line with the Company's efforts of divesting of marginal properties with high operating costs and acquiring incremental interests in offshore properties which have historically had lower operating costs per BOE. Operating costs per BOE were $3.76 compared to $3.99 in 1995. Direct operating margin from gas transportation, processing and marketing for 1996 was $2.6 million compared to $8.9 million in 1995. The decrease resulted primarily from a reduction in processing margins due to the sale of the Company's Wattenberg gas processing facilities which was completed in the third quarter of 1995. The Company realized almost $80 million in sales proceeds during 1995 on these facilities and recognized a total of $8.7 million in gains. Gains on sales of investments were $69.3 million in 1996, compared to $2.2 million in 1995. The $65.5 million gain on the Command exchange accounted for the bulk of the increase. The remaining gains are primarily due to sales of a portion of the Company's interests in the Permtex venture in Russia and the Tamtsag venture in Mongolia. In January 1997, the Company's interest in the Tamtsag venture was further reduced. 22 Gains on sales of properties were $8.8 million in 1996, compared to $12.3 million in 1995. The most significant gain during 1996 was a $7.4 million gain on the sale of a 50% interest in the Green River Basin holdings for $16.9 million. The most significant gain during 1995 was the $8.7 million gain recognized as part of the sale of the Company's Wattenberg gas processing facilities for almost $80 million. Other income increased 50% or $2.4 million from 1995. The increase can be primarily attributed to equity in earnings of Command increasing $1.9 million from the equity in losses recorded in 1995. Exploration expenses for 1996 were $4.2 million, down $3.8 million from 1995. The decrease was due primarily to a writeoff of $4.1 million of acreage costs in 1995 that was not incurred in 1996. Included in the 1996 expenditures of $4.2 million was a $1.2 million dry hole drilled in the Gulf of Mexico in the third quarter on an unexplored block adjacent to one of the Company's current producing blocks. General and administrative expenses, net of reimbursements, for 1996 were $17.1 million as compared to $17.7 million in 1995. The slight decrease is the result of ongoing expense reduction efforts and reductions in personnel due to the property divestitures that have taken place over the past two years offset somewhat by increased expenses related to the acquisition of Gerrity Oil & Gas Corporation ("GOG"). Interest and other expense was $28.9 million compared to $27.0 million in 1995. The majority of the increase is the result of a higher average interest rate primarily due to Patina's subordinated notes which have an effective interest rate of 11.1%. Depletion, depreciation and amortization expense in 1996 increased to $84.5 million from $76.4 million in 1995. The increase reflects an increase in the overall depletion, depreciation and amortization rate per equivalent barrel from $5.80 to $6.41. This increase can be attributed to downward revisions in reserve quantities at year end 1995 primarily in proved undeveloped reserves which became uneconomic at year end 1995 prices and the growing impact of the Gulf of Mexico operations which are typically more capital intensive thus having a higher depletion rate. COMPARISON OF 1995 RESULTS TO 1994. Total revenues for 1995 were $202.2 million, a $60.2 million decline from 1994. The revenue decrease included $56 million as a result of the suspension of low margin third party gas marketing activities late in 1994 and a $13 million decrease due to the sale of the Company's Wattenberg gas facilities in 1995. Oil and gas sales, on the other hand, rose by 5% to $144.6 million as a result of a 13% growth in production of barrels of oil equivalent. The production increase was partially offset by a 7% decrease in the average price received per BOE. Natural gas prices dropped sharply by 19% in 1995 to an average of $1.35 per Mcf, the lowest average price received in the Company's history. Oil prices improved 15% to average $16.96 per barrel during 1995. The net loss for 1995 was $39.8 million, compared to net income in 1994 of $12.4 million. The 1995 loss was primarily due to $27.4 million in noncash property impairment charges and almost $11 million in losses as a result of a litigation settlement, losses on marketable securities, as well as severance and restructuring costs. The property impairment charges resulted from the fourth quarter adoption of Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". Prior to the fourth quarter of 1995, the Company provided impairments for significant proved and unproved oil and gas property groups to the extent that net capitalized costs exceeded the undiscounted future cash flows. SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed discounted expected future cash flows. The decline from the 1994 net income also resulted from the decrease in natural gas prices and sharply increased financing costs, incurred prior to the reduction in outstanding debt accomplished during the latter half of 1995. Revenues from production operations, less direct operating expenses, for 1995 were $92.1 million, slightly greater than the 1994 net revenue. Average daily production during 1995 was 36,024 BOE, up 13% from 1994 levels, although the average product price received decreased by 7% to $11.00 per BOE. The production increase resulted primarily from newly drilled wells placed on 23 production late in 1994 and during early 1995. In 1995, the Company placed 223 wells on sales, including 88 in the DJ Basin of Colorado, 24 in the Austin Chalk area of Texas, 16 in the Green River Basin of Wyoming and six in the Piceance basin of western Colorado. Additionally, late in 1995, the Company sold its minor interest in a south Texas field where 70 nonoperated wells had been completed earlier in the year. In the DJ Basin, the Company completed 360 wells in 1994, but reduced its drilling in 1995 in response to the dramatic decrease in natural gas prices in the region. The Company expects to maintain a reduced development schedule in 1996. Total operating expenses for 1995 increased by 13%, in line with the production growth. Operating costs per BOE were $3.99, essentially even with those of the prior year. Revenues from gas processing, transportation, and marketing, less direct expenses, for 1995 were $8.9 million, compared to $13.1 million in 1994. The decrease resulted primarily from a reduction in processing margins due to the sale of the Company's Wattenberg processing facilities. During 1995, the Company realized almost $80 million in sales proceeds and recorded $8.7 million in gains. In conjunction with the sales, the Company completed an agreement with the primary purchaser, which, at current gas prices, is not expected to have a material adverse effect on the wellhead net prices compared to the Company's processing arrangements prior to the sale. Gas transportation and gathering margins from facilities retained by the Company climbed 47% during 1995 to $3.4 million, associated with rising production and system expansions in southern Wyoming and western Colorado. Gas marketing net revenues declined by $797,000 between years, after the suspension of third party marketing activities in late 1994. Gains on sales of properties were $12.3 million in 1995, compared to $2.0 million in 1994. The $8.7 million gain from the DJ Basin facility sales accounted for the bulk of the increase. The remaining gains were part of the Company's ongoing program to dispose of nonstrategic assets at favorable prices. Other income in 1995 was $7.0 million, which was reduced from $15.3 million in 1994, as the prior year included $6.6 million in gains on the sale of a portion of the Company's interest in the Permtex venture in Russia and the sale of equity securities by the Company's Australian affiliate. The remaining decrease was primarily due to losses on the sale of marketable securities in 1995. The Company realized $13.1 million in proceeds from the securities sales, which was applied to further reduce the outstanding debt. Exploration expenses for 1995 were $8.0 million, up $1.5 million from 1994. The increase resulted primarily from the writeoff of $4.1 million of certain acreage costs. General and administrative expenses, net of reimbursements, were $17.7 million as compared to $12.9 million in 1994. The increase consists of $2.3 million associated with an increase of activities related to the Company's newer development projects, $1.5 million in severance and restructuring costs primarily related to the Wattenberg Area activities and $1.0 million related to the expanding offshore operations. Interest and other expense was $27.0 million in 1995, up from $12.5 million in 1994. The majority of the increase was due to higher outstanding debt levels at higher average interest rates, and to a lesser extent, the writedown of certain notes receivable to their realizable value. Senior debt was significantly reduced during the last half of the year with the proceeds from the sale of the Wattenberg facilities and the west Texas oil and gas properties. Depletion, depreciation and amortization expense increased 8% during 1995. The increase resulted from the 13% growth in oil and gas production, offset somewhat by a reduction in the average depletion, depreciation and amortization rate per BOE to $5.00 in 1995 from $5.37 in 1994. The effective income tax rate for 1995 was a benefit of three percent. This benefit was limited to the extent of the net deferred tax liability at December 31, 1994 of $591,000 and the realization of a $779,000 deferred tax asset that was previously recorded to stockholders' equity as required by SFAS No. 115. DEVELOPMENT, ACQUISITION AND EXPLORATION During 1996, the Company incurred $349.0 million in capital expenditures, including $297.7 million for property acquisitions, $43.1 million for development, $4.6 million for exploration, $2.0 million for field and office equipment and $1.6 million for gas facility expansion. 24 The Company expended $297.7 million relating to property acquisitions during 1996. Of this amount, $273.1 million was for producing properties and $24.6 million was for unevaluated properties. Of the $273.1 million expended for producing properties, $218.4 million related to the formation of Patina and the subsequent May 1996 acquisition (the "Acquisition") of GOG. In 1996, the Company acquired, via three acquisitions, incremental interests in certain properties located in the Gulf of Mexico for a net purchase price of $72.1 million ($22.4 million was classified as unevaluated properties). Of the total development expenditures, $12.8 million was concentrated in the Gulf of Mexico where four wells were placed on sales with three in progress at year end. The Company expended $8.6 million in the Piceance Basin of western Colorado to place 22 wells on sales with one in progress at year end. The Company expended $5.7 million in the East Washakie Basin of southern Wyoming to place twelve wells on sales with three in progress at year end. In the Green River Basin of southern Wyoming, $2.9 million was incurred to place five wells on sales with two in progress at year end. Exploration costs in 1996 were $4.6 million primarily for seismic work performed in and around the Company's major drilling projects and a dry hole drilled in the Gulf of Mexico. In Russia, ten additional wells were drilled and completed resulting in that venture increasing production to over 3,500 barrels per day. Drilling activity has been slower than anticipated due to difficulties in securing drilling contracts on commercially reasonable terms. During 1997, the Company expects to drill 11 wells. In Mongolia, the Mongolian Parliament ratified the grant of two additional concessions in the area to SOCO Tamtsag Mongolia, Inc. bringing the total acreage position to approximately 10 million acres. During 1996, two exploratory wells were drilled, one of which resulted in a second discovery. SOCO Tamtsag Mongolia, Inc. intends to drill four wells during 1997. In Thailand, the Company was awarded Block B8/38 in the Gulf of Thailand. The Company has entered into an agreement with an international oil company which will fund the drilling of an exploration well in this block. Drilling is expected to begin in the second quarter, with a second well possibly being drilled by year end. FINANCIAL CONDITION AND CAPITAL RESOURCES At December 31, 1996, the Company had total assets of $879.5 million. Total capitalization was $675.8 million, of which 44% was represented by stockholder's equity, 28% by senior debt, 27% by subordinated debt and 1% by deferred taxes payable. During 1996, net cash provided by operations was $101.7 million, an increase of 47% compared to 1995. As of December 31, 1996, commitments for capital expenditures totaled $7.3 million. The Company anticipates that 1997 expenditures for development drilling will approximate $112 million. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development acquisition and exploration expenditures using internally generated cash flow and existing credit facilities. The Company is also considering a public offering for a subsidiary which holds certain of the Company's international investments. The Company expects the offering to be completed in 1997 with the securities being listed on a major international stock exchange. In addition, joint ventures or future public offerings of debt or equity securities may be utilized. As a result of the Acquisition, the Company has realized increased net cash provided by operations. For the foreseeable future, cash generated by Patina will, however, be retained by Patina to fund its development program, reduce debt and pursue acquisitions in the DJ Basin or elsewhere. Moreover, Patina's credit facilities currently prohibit the payment of dividends on its common stock. Accordingly, Patina's cash flow is intended to be used to reduce debt levels, fund a limited development program and any future acquisitions which may be consummated and may not be available to fund the Company's other operations or to pay dividends to its stockholders. SOCO maintains a $500 million revolving credit facility (the "SOCO Facility"). The SOCO Facility is divided into a $100 million short-term portion and a $400 million long-term portion that expires on December 31, 2000. Management's policy is to renew the facility on a regular basis. Credit availability is adjusted semiannually to reflect changes in reserves and asset values. The borrowing base available under the facility at December 31, 1996 was $140 million. Financial covenants limit debt, require maintenance of $1.0 million in minimum working capital as defined and restrict certain payments, including stock repurchases, dividends and contributions or advances to 25 unrestricted subsidiaries. Such restricted payments are limited by a formula that includes underwriting proceeds, cash flow and other items. Based on such limitations, more than $60 million was available for the payment of dividends and other restricted payments as of December 31, 1996. Simultaneously with the Acquisition, Patina entered into a bank credit agreement. The agreement consists of (i) a facility provided to Patina and SOCO Wattenberg (the "Patina Facility") and (ii) a facility provided to GOG (the "GOG Facility"). The Patina Facility is a revolving credit facility in an aggregate amount up to $102 million. The amount available for borrowing under the revolving credit facility will be limited to a semiannually adjusted borrowing base that equaled $85 million at December 31, 1996. At December 31, 1996, $67.5 million was outstanding under the revolving credit facility. Subsequent to the Acquisition, Patina has utilized primarily cash flow from operations to reduce the balance outstanding under the Patina Facility by more than $14 million. The GOG Facility is a revolving credit facility in an aggregate amount up to $51 million. The amount available for borrowing under the GOG Facility will be limited to a fluctuating borrowing base that equaled $35 million at December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the GOG Facility. The GOG Facility was used primarily to refinance GOG's previous bank credit facility and pay for costs associated with the Acquisition. Subsequent to the Acquisition, Patina has utilized primarily cash flow from operations to reduce the balance outstanding under the GOG Facility by more than $7 million. Patina's bank credit agreement contains certain financial covenants including, but not limited to, a maximum total debt to capitalization ratio, a maximum total debt to EBITDA ratio and a minimum current ratio. The bank credit agreement also contains certain negative covenants, including but not limited to restrictions on indebtedness; certain liens; guarantees, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge clauses; issuance of securities; and non-speculative commodity hedging. The Company from time to time enters into arrangements to monetize its Section 29 tax credits. These arrangements result in revenue increases of approximately $.40 per Mcf on production volumes from qualified Section 29 properties. As a result of such arrangements, the Company recognized additional gas sales of $2.5 million in both years ended December 31, 1995 and 1996. These arrangements are expected to increase revenues through 2002. The Company seeks to diversify its exploration and development risks by seeking partners for its significant development projects and maintains a program to divest marginal properties and assets which do not fit its long range plans. During 1996, the Company received $73.6 million in proceeds from the sale of oil and gas properties which were used to reduce debt and finance additional acquisitions in the Gulf of Mexico. The most significant sales arose from the addition of partners in two of the Company's major development projects. The largest sale was the sale of a 45% interest in its Piceance Basin holdings for a sale price of $22.4 million. The Company recognized a net gain of $2.4 million as a result of this transaction. In addition, the Company sold a 50% interest in its Green River Basin gas project for $16.9 million. The Company recognized a net gain of $7.4 million as a result of this transaction. Proceeds from the sale of nonstrategic properties totaled $34.3 million. The largest of these sales was the sale in December 1996 of the Company's interests in the Giddings Field of southeast Texas for $11.8 million. The Company recognized a net loss of $3.3 million as a result of this transaction. In November 1996, the Company accepted an offer from Cairn for its interest in Command. The Company received 16.2 million shares of freely marketable Cairn common stock, and recorded a gain of $65.5 million, with no associated current tax liability. However, a deferred tax provision of $4.0 million was recorded related to this transaction. Immediately prior to the acceptance of Cairn's offer, the Company accrued for a transaction in which a director of the Company exchanged his option to purchase 10% of the outstanding common stock of SOCO International, Inc. (through which the investment in Command was held) and issued promissory notes to the Company totaling $591,000 for 10% of the outstanding common stock of two SOCO International, Inc. 26 subsidiaries, SOCO International Holdings, Inc. and SOCO International Operations, Inc. As a result of this transaction, the Company recorded a $260,000 loss on the exchange. Additionally, minority interest expense of $4.3 million was recorded related to the director's 10% ownership as a result of the Command gain. The actual exchange occurred in December 1996 and the promissory notes remained outstanding at year end. Subsequent to year end, the Company sold 4.5 million Cairn shares at an average of $8.81 per share realizing $39.2 million in proceeds which will be used primarily to reduce senior debt. These transactions are anticipated to result in a pretax gain of $11.7 million (after minority interest expense of $1.3 million) in the first quarter of 1997. During the second quarter of 1996, the Board authorized the repurchase of up to $10 million of the Company's securities and in the third quarter of 1996, authorized an additional $10 million for this purpose. During the last three quarters of 1996, the Company repurchased 725,000 common shares for $7.0 million, 6,000 preferred depository shares for $142,000 and $3.8 million face value convertible subordinated notes for $3.5 million. Additional repurchases have and may continue to be made at such times and at such prices as the Company deems appropriate. The Company believes that its capital resources are adequate to meet the requirements of its business. However, future cash flows are subject to a number of variables including the level of production and oil and gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. 27 INFLATION AND CHANGES IN PRICES While certain of its costs are affected by the general level of inflation, factors unique to the petroleum industry result in independent price fluctuations. Over the past five years, significant fluctuations have occurred in oil and gas prices. Although it is difficult to estimate future prices of oil and gas, price fluctuations have had, and will continue to have, a material effect on the Company. The following table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 1995 and 1996. Average gas prices for 1995 and 1996 were increased by $.06 and $.08 per Mcf, respectively, by the benefit of the Company's hedging activities. Average price computations exclude contract settlements and other nonrecurring items to provide comparability. Average prices per equivalent barrel indicate the composite impact of changes in oil and gas prices. Natural gas production is converted to oil equivalents at the rate of 6 Mcf per barrel.
AVERAGE PRICES ------------------------------------------- CRUDE OIL AND NATURAL EQUIVALENT LIQUIDS GAS BARRELS --------- --------- ---------- (PER BBL) (PER MCF) (PER BOE) ANNUAL ------ 1992 $ 18.87 $ 1.74 $ 13.76 1993 15.41 1.94 13.41 1994 14.80 1.67 11.82 1995 16.96 1.35 11.00 1996 20.39 1.97 14.35 QUARTERLY --------- 1995 ---- First $ 16.40 $ 1.31 $ 10.66 Second 17.52 1.29 10.95 Third 17.05 1.30 10.81 Fourth 16.84 1.55 11.69 1996 ---- First $ 17.95 $ 1.78 $ 12.80 Second 20.52 1.62 12.90 Third 20.25 1.78 13.60 Fourth 22.26 2.64 17.69
In December 1996, the Company received an average of $22.19 per barrel and $3.68 per Mcf for its production. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA Reference is made to the Index to Consolidated Financial Statements on page 29 for the Company's consolidated financial statements and notes thereto. Quarterly financial data for the Company is presented on page 21 of this Form 10-K. Supplementary schedules for the Company, other than Schedule I, have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES. None. 28 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS PAGE Report of Independent Public Accountants....................................30 Consolidated Balance Sheets as of December 31, 1995 and 1996................31 Consolidated Statements of Operations for the years ended December 31, 1994, 1995 and 1996...................32 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1994, 1995 and 1996...................33 Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1995 and 1996...................34 Notes to Consolidated Financial Statements..................................35 Schedules: Schedule I-Condensed Financial Information of Snyder Oil Corporation ..54 29 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE STOCKHOLDERS OF SNYDER OIL CORPORATION: We have audited the accompanying consolidated balance sheets of Snyder Oil Corporation (a Delaware corporation) and subsidiaries as of December 31, 1995 and 1996, and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company'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, the financial statements referred to above present fairly, in all material respects, the financial position of Snyder Oil Corporation and subsidiaries as of December 31, 1995 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. As explained in Note 2 to the financial statements, the Company adopted Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", in 1995. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplementary schedules listed in the index to the consolidated financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a required part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Fort Worth, Texas, February 17, 1997 30 SNYDER OIL CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
DECEMBER 31, -------------------------------- 1995 1996 ------------- ------------- ASSETS Current assets Cash and equivalents $ 27,263 $ 27,922 Accounts receivable 29,259 58,944 Inventory and other 11,769 11,212 ----------- ----------- 68,291 98,078 ----------- ----------- Investments 33,220 129,681 ----------- ----------- Oil and gas properties, successful efforts method 675,961 887,721 Accumulated depletion, depreciation and amortization (240,744) (252,334) ----------- ----------- 435,217 635,387 ----------- ----------- Gas facilities and other 30,506 28,111 Accumulated depreciation and amortization (11,741) (11,798) ----------- ----------- 18,765 16,313 ----------- ----------- $ 555,493 $ 879,459 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 36,353 $ 51,867 Accrued liabilities 26,096 37,043 ----------- ----------- 62,449 88,910 ----------- ----------- Senior debt 150,001 188,231 Subordinated notes - 103,094 Convertible subordinated notes 84,058 80,748 Deferred taxes payable - 9,034 Other noncurrent liabilities 20,016 28,064 Minority interest 3,601 86,710 Commitments and contingencies Stockholders' equity Preferred stock, $.01 par, 10,000,000 shares authorized, 6% Convertible preferred stock, 1,035,000 and 1,033,500 shares issued and outstanding 10 10 Common stock, $.01 par, 75,000,000 shares authorized, 31,430,227 and 31,456,027 issued 314 315 Capital in excess of par value 265,911 260,221 Retained earnings (deficit) (29,001) 25,711 Common stock held in treasury, 134,191 and 250,000 shares at cost (2,457) (3,510) Unrealized foreign currency translation gain 380 - Unrealized gain on investments 211 11,921 ----------- ----------- 235,368 294,668 ----------- ----------- $ 555,493 $ 879,459 =========== =========== The accompanying notes are an integral part of these statements.
31 SNYDER OIL CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, --------------------------------------------- 1994 1995 1996 ----------- ----------- ----------- Revenues Oil and gas sales $ 137,858 $ 144,608 $ 189,327 Gas transportation, processing and marketing 107,247 38,256 17,655 Gains on sales of equity interests in investees 9,747 2,183 69,343 Gains on sales of properties 1,969 12,254 8,786 Other 5,507 4,859 7,303 --------- --------- --------- 262,328 202,160 292,414 --------- --------- --------- Expenses Direct operating 46,267 52,486 49,638 Cost of gas and transportation 94,177 29,374 15,020 Exploration 6,505 8,033 4,232 General and administrative 12,853 17,680 17,143 Interest and other 12,463 27,001 28,899 Litigation settlement - 4,400 - Loss on sale of subsidiary interest - - 15,481 Depletion, depreciation and amortization 70,770 76,378 84,547 Property impairments 5,783 27,412 2,753 --------- --------- --------- Income (loss) before taxes and minority interest 13,510 (40,604) 74,701 --------- --------- --------- Provision (benefit) for income taxes Current - 25 33 Deferred 967 (1,370) 4,313 --------- --------- --------- 967 (1,345) 4,346 --------- --------- --------- Minority interest (171) (572) (7,405) --------- --------- --------- Net income (loss) $ 12,372 $ (39,831) $ 62,950 ========= ========= ========= Net income (loss) per common share $ .07 $ (1.53) $ 1.81 ========= ========= ========= Weighted average shares outstanding 23,704 30,186 31,308 ========= ========= ========= The accompanying notes are an integral part of these statements.
32 SNYDER OIL CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (IN THOUSANDS)
PREFERRED STOCK COMMON STOCK CAPITAL IN RETAINED --------------- ---------------- EXCESS OF EARNINGS TREASURY SHARES AMOUNT SHARES AMOUNT PAR VALUE (DEFICIT) STOCK ------ ------ ------ ------ --------- --------- -------- Balance, December 31, 1993 2,221 $ 22 23,260 $ 233 $ 249,713 $ 25,308 $ - Common stock grants and exercise of options - - 414 4 2,851 - (2,288) Conversion of preferred to common (1,186) (12) 6,535 65 (53) - - Issuance of warrants - - - - 3,450 - - Dividends - - - - - (16,721) - Net income - - - - - 12,372 - ------- ------ ------- ------ --------- --------- -------- Balance, December 31, 1994 1,035 10 30,209 302 255,961 20,959 (2,288) Common stock grants and exercise of options - - 138 1 856 - (169) Issuance of common - - 1,083 11 13,021 - - Dividends - - - - (3,927) (10,129) - Net loss - - - - - (39,831) - ------- ------ ------- ------ --------- --------- -------- Balance, December 31, 1995 1,035 10 31,430 314 265,911 (29,001) (2,457) Common stock grants and exercise of options - - 267 3 3,179 - (258) Issuance of common - - 399 4 3,689 - - Repurchase of common - - (640) (6) (6,243) - (795) Repurchase of preferred (1) - - - (142) - - Dividends - - - - (6,173) (8,238) - Net income - - - - - 62,950 - ------- ------ -------- ------ --------- -------- -------- Balance, December 31, 1996 1,034 $ 10 31,456 $ 315 $ 260,221 $ 25,711 $ (3,510) ======= ====== ======== ====== ========= ======== ======== The accompanying notes are an integral part of these statements.
33 SNYDER OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ---------------------------------------------- 1994 1995 1996 ------------ ------------ ----------- Operating activities Net income (loss) $ 12,372 $ (39,831) $ 62,950 Adjustments to reconcile net income (loss) to net cash provided by operations Amortization of deferred credits (2,986) (2,511) (1,052) Gains on sales of investments (9,747) (809) (68,343) Gains on sales of properties (1,969) (12,254) (8,786) Equity in (earnings) losses of unconsolidated subsidiaries (1,355) 1,319 (421) Exploration expense 6,505 8,033 4,232 Loss on sale of subsidiary interest - - 15,481 Depletion, depreciation and amortization 70,770 76,378 84,547 Property impairments 5,783 27,412 2,753 Deferred taxes 967 (1,370) 4,313 Minority interest 171 572 7,405 Changes in current and other assets and liabilities Decrease (increase) in Accounts receivable 11,024 7,142 (15,869) Inventory and other (9,241) 3,617 5,175 Increase (decrease) in Accounts payable 1,901 (8,521) 2,771 Accrued liabilities 1,841 5,165 (316) Other liabilities 361 4,779 6,890 ------------ ------------ ----------- Net cash provided by operations 86,397 69,121 101,730 ------------ ------------ ----------- Investing activities Acquisition, development and exploration (237,879) (92,353) (128,598) Purchase of controlling interest in subsidiary (6,645) - - Proceeds from investments 5,019 14,786 1,635 Outlays for investments (8,804) - (9,013) Proceeds from sales of properties 2,806 109,988 73,620 ------------ ------------ ----------- Net cash realized (used) by investing (245,503) 32,421 (62,356) ------------ ------------ ----------- Financing activities Issuance of common 1,157 688 1,523 Increase (decrease) in indebtedness 187,138 (86,193) (13,289) Debt issuance costs (2,855) - - Dividends (16,721) (14,056) (14,411) Deferred credits 2,356 3,549 (120) Repurchase of stock (1,149) - (7,186) Repurchase of subordinated notes - - (5,232) ------------ ------------ ----------- Net cash realized (used) by financing 169,926 (96,012) (38,715) ------------ ------------ ----------- Increase in cash 10,820 5,530 659 Cash and equivalents, beginning of year 10,913 21,733 27,263 ------------ ------------ ----------- Cash and equivalents, end of year $ 21,733 $ 27,263 $ 27,922 ============ ============ =========== Noncash investing and financing activities Gas plant capital lease $ 21,000 - - Acquisition of properties and stock via stock issuances - $ 13,032 $ 3,693 Acquisition of properties recorded as senior debt - - $ 31,730 Acquisition via subsidiary stock issuance - - $ 115,067 The accompanying notes are an integral part of these statements.
34 SNYDER OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) ORGANIZATION AND NATURE OF BUSINESS Snyder Oil Corporation (the "Company") is primarily engaged in the acquisition, exploration and development of oil and gas properties principally in the Rocky Mountain and Gulf Coast regions of the United States. To a minor extent, the Company gathers, transports and markets natural gas generally in proximity to its principal producing properties. The Company is also engaged in international acquisition, exploration and development, primarily through affiliates. The Company, a Delaware corporation, is the successor to a company formed in 1978. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The consolidated financial statements include the accounts of Snyder Oil Corporation ("SOCO") and its subsidiaries (collectively, the "Company"). Affiliates in which the Company owns more than 50% but less than 100% are fully consolidated, with the related minority interest being deducted from subsidiary earnings and stockholders' equity. Affiliates being accounted for in this manner include Patina Oil & Gas Corporation ("Patina"), SOCO International Holdings, Inc. ("Holdings") and SOCO International Operations, Inc. ("Operations"). DelMar Petroleum, Inc., whose name was subsequently changed to SOCO Offshore, Inc. ("SOCO Offshore"), was accounted for in this manner until all remaining minority interests were acquired in June 1996. Affiliates in which the Company owns between 20% and 50% are accounted for under the equity method. Affiliates being accounted for in this manner include SOCO Perm Russia, Inc. ("SOCO Perm"), a Russian affiliate, and SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"), a Mongolian affiliate. Command Petroleum Limited ("Command"), an Australian affiliate, was accounted for in this manner until the Company disposed of this investment in November 1996. Affiliates in which the Company owns less than 20% are accounted for under the cost method. Affiliates being accounted for in this manner include Cairn Energy plc ("Cairn"). The Company accounts for its interest in joint ventures and partnerships using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are consolidated. Producing Activities The Company utilizes the successful efforts method of accounting for its oil and gas properties. Consequently, leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments in value are charged to expense. During the year ended December 31, 1996, the Company provided unproved property impairments of $2.8 million. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis over the life of the remaining proved or proved developed reserves, as applicable. Gas is converted to equivalent barrels at the rate of 6 Mcf to 1 barrel. Amortization of capitalized costs is generally provided on a property-by-property basis. Estimated future abandonment costs (net of salvage values) are accrued at unit-of-production rates and taken into account in determining depletion, depreciation and amortization. Prior to 1995, the Company provided impairments for significant proved oil and gas property groups to the extent that net capitalized costs exceeded the undiscounted future cash flows. During 1995, the Company adopted Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a property-by-property basis. If an impairment is indicated based on undiscounted expected future cash flows, then it is recognized to the extent that net capitalized costs exceed discounted expected future cash flows. Accordingly, in 1995 the Company provided for $27.4 million of such impairments. During the year ended December 31, 1996, the Company did not provide for any such impairments. 35 Unrealized Foreign Currency Translation Gain The company follows SFAS 52, "Foreign Currency Translation", which requires that business transactions and foreign operations recorded in a foreign currency must be restated in U.S. dollars. Gains or losses resulting from the translation process increases or decreases the book value of investments and must be accumulated in a separate component of stockholders' equity. Command's functional currency is the Australian dollar. The foreign currency translation gain reported in the balance sheet as of December 31, 1995 was the result of the translation of the Australian dollar balance sheet into United States dollars at then current exchange rates. Section 29 Tax Credits The Company from time to time enters into arrangements to monetize its Section 29 tax credits. These arrangements result in revenue increases of approximately $.40 per Mcf on production volumes from qualified Section 29 properties. As a result of such arrangements, the Company recognized additional gas revenues of $2.5 million in both 1995 and 1996. These arrangements are expected to continue through 2002. Gas Imbalances The Company uses the sales method to account for gas imbalances. Under this method, revenue is recognized based on the cash received rather than the proportionate share of gas produced. Gas imbalances at year end 1995 and 1996 were insignificant. Financial Instruments The following table sets forth the book value and estimated fair values of financial instruments (in thousands):
DECEMBER 31, DECEMBER 31, 1995 1996 ---------------------- ---------------------- BOOK FAIR BOOK FAIR VALUE VALUE VALUE VALUE --------- --------- --------- --------- Cash and equivalents $ 27,263 $ 27,263 $ 27,922 $ 27,922 Investments 33,220 52,203 129,681 163,477 Senior debt (150,001) (150,001) (188,231) (188,231) Subordinated notes - - (103,094) (105,650) Convertible subordinated notes (84,058) (79,997) (80,748) (82,866) Long-term commodity contracts - 11,623 - 5,040 Interest rate swap - 107 - (19)
The book value of cash and equivalents approximates fair value because of the short maturity of those instruments. See Note (3) for a discussion of the Company's investments. The fair value of senior debt is presented at face value given its floating rate structure. The fair value of the subordinated notes and convertible subordinated notes are estimated based on their December 31, 1996 closing prices on the New York Stock Exchange. From time to time, the Company enters into commodity contracts to hedge the price risk of a portion of its production. Gains and losses on such contracts are deferred and recognized in income as an adjustment to oil and gas sales revenue in the period to which the contracts relate. In 1994, the Company entered into a long-term gas swap arrangement in order to lock in the price differential between the Rocky Mountain and Henry Hub prices on a portion of its Rocky Mountain gas production. The contract covers 20,000 MMBtu per day through 2004. In December 1996, that volume represented approximately 43% of SOCO's Rocky Mountain gas production and 17% of the Company's consolidated Rocky Mountain gas production. The fair value of the contract was based on the market price quoted for a similar instrument. 36 In September 1995, the Company entered into an interest rate swap covering $50 million of its bank debt. The agreement requires payment to a counterparty based on a fixed rate of 5.585% and requires the counterparty to pay the Company interest at the then current 30 day LIBOR rate. Accounts receivable or payable under this agreement are recorded as adjustments to interest expense and are settled on a monthly basis. The agreement matures in September 1997, with the counterparty having the option to extend it for two years. At December 31, 1996, the fair value of the agreement was estimated at the net present value discounted at 10%. Risks and Uncertainties Historically, the market for oil and gas has experienced significant price fluctuations. Prices for gas in the Rocky Mountain region, where the Company currently produces over 70% of its natural gas, have traditionally been particularly volatile. Prices are significantly impacted by the local weather, production in the area, seasonal variations in local demand and limited transportation capacity to other regions of the country. Until recently, mild weather and increased production in the region contributed to depressed prices. At December 31, 1996, prices in the region had rebounded sharply, although it is uncertain if this trend will continue. Increases or decreases in prices received, particularly in the Rocky Mountains, could have a significant impact on the Company's future results of operations. The Company's strategy internationally is to develop a portfolio of projects that have the potential to make a major contribution to its production and reserves while limiting its financial exposure and mitigating political risk by seeking industry partners and investors to fund the majority of the required capital. Such projects are subject to a number of political and economic uncertainties, in addition to the typical risks and volatility associated with the oil and gas industry. There is no assurance that the Company's international operations will reach a level reasonably required to fully exploit the projects, nor is there any assurance of economic success should such a level be reached. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Other All liquid investments with an original maturity of three months or less are considered to be cash equivalents. Certain amounts in prior years consolidated financial statements have been reclassified to conform with current classification. (3) INVESTMENTS The Company has investments in foreign and domestic energy companies and long-term notes receivable. The following table sets forth the book values and estimated fair values of these investments:
DECEMBER 31, 1995 DECEMBER 31, 1996 ----------------------- ------------------------ (IN THOUSANDS) BOOK FAIR BOOK FAIR VALUE VALUE VALUE VALUE --------- --------- --------- --------- Equity method investments $ 30,901 $ 49,884 $ 8,789 $ 42,585 Marketable securities 652 652 115,558 115,558 Long-term notes receivable 1,667 1,667 5,334 5,334 --------- --------- --------- --------- $ 33,220 $ 52,203 $ 129,681 $ 163,477 ========= ========= ========= =========
The Company follows SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities", which requires that investments in marketable 37 securities accounted for on the cost method and long-term notes receivable must be adjusted to their market value with a corresponding increase or decrease to stockholders' equity. The pronouncement does not apply to investments accounted for by the equity method. Command Petroleum Limited From May 1993 to November 1996, the Company had an investment in Command, an Australian oil company, accounted for by the equity method. Command was listed on the Australian Stock Exchange. In 1995, the Company acquired an additional 4.7 million shares of Command common stock in exchange for an interest in the Fejaj Permit in Tunisia. As a result, the Company's ownership in Command increased to 30.0% and a $1.4 million gain was recognized during 1995. In June 1996, the Company purchased 8.5 million shares of Command common stock for $3.6 million, increasing its ownership to 32.6%. In October 1996, Command announced that it had completed merger negotiations with Cairn, an international independent oil company based in Edinburgh, Scotland with shares listed on the London Stock Exchange. In November 1996, the Company accepted Cairn's offer for its interest in Command. The Company received 16.2 million shares of freely marketable Cairn common stock, and recorded a gain of $65.5 million in the fourth quarter of 1996. The Company's investment in Cairn is accounted for under the cost method and is reflected as marketable securities in the table above. Immediately prior to the acceptance of Cairn's offer, the Company accrued for a transaction in which a director of the Company exchanged his option to purchase 10% of the outstanding common stock of SOCO International, Inc. (through which the investment in Command was held) and issued promissory notes to the Company totaling $591,000 for 10% of the outstanding common stock of two SOCO International, Inc. subsidiaries, Holdings and Operations. As a result of this transaction, the Company recorded a $260,000 loss on the exchange. Additionally, minority interest expense of $4.3 million was recorded related to the director's 10% ownership as a result of the Command gain. The actual exchange occurred in December 1996 and the promissory notes remained outstanding at year end. SOCO Perm Russia, Inc. In 1993, SOCO Perm was organized by the Company and a U.S. industry participant. SOCO Perm and a Russian partner formed the Permtex joint venture to develop proven oil fields in the Volga-Urals Basin of Russia. To finance a portion of its planned development expenditures, SOCO Perm closed a private placement of its equity securities with three industry participants in 1994. As a result, the Company's investment was reduced from 75% to 41.25% and a $3.5 million net gain was recorded. In 1995, the three industry participants paid the final installments of their contributions to SOCO Perm and as a result, the Company recognized an additional gain of $1.1 million. In April 1996, SOCO Perm closed a private placement which reduced the Company's interest to 34.91% and indicated a market value of $22.7 million for the Company's remaining position. The Company recognized a gain in the second quarter of $2.6 million as a result of this transaction. The private placement agreement requires SOCO Perm to list its common shares on a securities exchange no later than 1998. If such listing does not occur, the new shareholders have the right to require the Company to purchase their share at a formula price. The Company's investment in SOCO Perm is held through Operations. The Company is currently considering the possibility of listing Operations on a major international Stock Exchange. If such listing was to occur, it is expected to meet the requirement to list SOCO Perm. The Company's investment in SOCO Perm had a carrying cost at December 31, 1996 of $7.0 million. SOCO Tamtsag Mongolia, Inc. In 1994, the Company formed a consortium to explore the Tamtsag Basin of eastern Mongolia, then sold a portion of its interest to three industry participants. One participant committed to fund the drilling of two wells, the second purchased its interest for cash and a third participant assigned its exploration rights in the basin to the consortium. Accordingly, the Company's investment in SOCO Tamtsag was reduced from 100% to 49% and a $1.5 million gain was recognized. In 1996, the Company completed the exchange of a portion of its interest to an industry participant for consulting services valued at $1.5 million. As a result of this transaction, the Company's ownership was reduced to 42% and an $832,000 gain was recognized. In August 1996, the Mongolian Parliament ratified the grant of two additional concessions in the area to SOCO Tamtsag, bringing the total acreage position to approximately 10 million acres. The Company's investment in SOCO Tamtsag had a carrying cost of $1.8 million at December 31, 1996 in addition to $4.7 million in stockholder loans, which are required on a pro rata basis by all stockholders, to SOCO Tamtsag which are included in notes receivable in the table above. In January 1997, SOCO Tamtsag completed an equity sale which reduced the Company's investment to 40.3% and 38 indicated a market value of $19.9 million for the Company's remaining position. The Company's investment in SOCO Tamtsag is held through Operations. Marketable Securities The Company had investments in equity securities of publicly traded domestic energy companies accounted for on the cost method, with a total cost at December 31, 1995 of $328,000. The market value of these securities at December 31, 1995 approximated $652,000. In 1996, the Company sold all of these securities for $968,000 and recognized a corresponding gain of $640,000. In accordance with SFAS 115 at December 31, 1995, investments were increased by $324,000 of gross unrealized holding gains, stockholders' equity was increased by $211,000 and deferred taxes payable were increased by $113,000. The Company had investments in equity securities of one publicly traded foreign energy company, Cairn, accounted for on the cost method at December 31, 1996. Cairn has a major development project off the coast of Bangladesh as well as major producing interests in the United Kingdom and the Dutch North Sea, and exploration interests in several countries including Thailand, Vietnam and China. The Company's total cost basis in the Cairn shares was $95.2 million at December 31, 1996. The market value of the Cairn shares approximated $115.6 million at December 31, 1996. In accordance with SFAS 115, at December 31, 1996, investments were increased by a $20.4 million gross unrealized holding gain, stockholders' equity was increased by $11.9 million, minority interest liability was increased by $1.3 million and deferred taxes payable were increased by $7.2 million. Subsequent to year end, the Company sold 4.5 million Cairn shares at an average of $8.81 per share realizing $39.2 million in proceeds which will be used primarily to reduce senior debt. These transactions are anticipated to result in a pretax gain of $11.7 million (after minority interest expense of $1.3 million) in the first quarter of 1997. Notes Receivable The Company holds long-term notes receivable due from SOCO Tamtsag, other privately held corporations and a director, with a book value of $1.7 million and $5.3 million at December 31, 1995 and 1996. SOCO Tamtsag shareholder loans, which bear interest at the three month LIBOR rate plus two percent, are to be repaid from the gross receipts of SOCO Tamtsag under certain circumstances (i.e., excess cash reserves). Any remaining balances mature December 31, 2009. The notes from other privately held corporations are secured by certain assets, including stock and oil and gas properties. The notes from a director, which originated in connection with an option to purchase 10% of the Company's international affiliates, are unsecured and are due April 10, 1998. The Company believes that, based on existing market conditions, the December 31, 1996 balances will be recovered in the long term. At December 31, 1995 and 1996, the fair value of the notes receivable, based on existing market conditions and the anticipated future net cash flow related to the notes, approximated their carrying cost. (4) OIL AND GAS PROPERTIES AND GAS FACILITIES The cost of oil and gas properties at December 31, 1995 and 1996 includes $24.2 million and $32.7 million, respectively, of unevaluated leasehold. Such properties are held for exploration, development or resale and are excluded from amortization. The following table sets forth costs incurred related to oil and gas properties and gas processing and transportation facilities:
1994 1995 1996 ---------- ---------- ---------- (IN THOUSANDS) Proved acquisitions $ 44,684 $ 13,675 $ 273,088 Acreage acquisitions 25,571 7,388 24,589 Development 156,912 62,578 43,075 Gas processing, transportation and other 46,607 7,886 3,612 Exploration 5,514 8,214 4,588 ---------- ---------- ---------- $ 279,288 $ 99,741 $ 348,952 ========== ========== ==========
During 1996, the Company incurred $273.1 million for domestic proved acquisitions. Of the total acquisition expenditures, $218.4 million related to the formation of Patina and the subsequent May 1996 acquisition (the "Acquisition") of Gerrity Oil & Gas Corporation ("GOG"). As a result, the Company initially retained 70% of the common stock of Patina and the former GOG 39 shareholders received 30% of the common stock. The Company currently owns 74% of Patina, and it is consolidated into the Company's financial statements. The Company recognized a net loss of $15.5 million in the second quarter of 1996 as a result of this transaction. In 1996, the Company acquired, via three acquisitions, incremental interests in certain properties located in the Gulf of Mexico for a net purchase price of $72.1 million ($22.4 million of which was classified as acreage acquisitions). Of the total development expenditures, $12.8 million was concentrated in the Gulf of Mexico where four wells were placed on sales with three in progress at year end. The Company expended $8.6 million in the Piceance Basin of western Colorado to place 22 wells on sales with one in progress at year end. The Company expended $5.7 million in the East Washakie Basin of southern Wyoming to place twelve wells on sales with three in progress at year end. In the Green River Basin of southern Wyoming, $2.9 million was incurred to place five wells on sales with two in progress at year end. In May 1996, the Company sold a 45% interest in its Piceance Basin holdings for $22.4 million. The Company recognized a net gain of $2.4 million as a result of this transaction. In July 1996, the Company sold a 50% interest in its Green River Basin gas project for $16.9 million. The Company recognized a net gain of $7.4 million as a result of this transaction. In December 1996, the Company sold its interests in the Giddings Field of southeast Texas for $11.8 million. The Company recognized a net loss of $3.3 million as a result of this transaction. The following table summarizes the unaudited pro forma effects on the Company's financial statements assuming significant acquisitions and divestitures consummated during 1996 had been consummated on January 1, 1995 and 1996. Future results may differ substantially from pro forma results due to changes in oil and gas prices, production declines and other factors. Therefore, pro forma statements cannot be considered indicative of future operations.
1995 1996 ----------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Oil and gas sales $ 189,734 $ 221,368 Total revenues $ 250,986 $ 324,127 Production direct operating margin $ 131,310 $ 170,612 Net income (loss) $ (43,638) $ 71,125 Net income (loss) per common share $ (1.65) $ 2.07 Weighted average shares outstanding 30,186 31,308
(5) INDEBTEDNESS The following indebtedness was outstanding on the respective dates:
DECEMBER 31, ------------------------------- 1995 1996 ----------- ----------- (IN THOUSANDS) SOCO bank facility $ 150,001 $ 93,731 Patina bank facilities - 94,500 Less current portion - - ----------- ----------- Senior debt $ 150,001 $ 188,231 =========== =========== Patina subordinated notes $ - $ 103,094 =========== =========== SOCO convertible subordinated notes $ 84,058 $ 80,748 =========== ===========
40 SOCO maintains a $500 million revolving credit facility ("SOCO Facility"). The facility is divided into a $400 million long-term portion and a $100 million short-term portion. The borrowing base available under the facility was $140 million at December 31, 1996. The majority of the borrowings under the facility currently bear interest at LIBOR plus .75% with the remainder at prime, with an option to select CD plus .75%. The margin on LIBOR or CD increases to 1% when the Company's consolidated senior debt becomes greater than 80% of its consolidated tangible net worth as defined. During 1996, the average interest rate under the revolver was 6.4%. The Company pays certain fees based on the unused portion of the borrowing base. Among other requirements, covenants require maintenance of a current working capital ratio of 1 to 1 as defined, limit the incurrence of debt and restrict dividends, stock repurchases, certain investments, other indebtedness and unrelated business activities. Such restricted payments are limited by a formula that includes underwriting proceeds, cash flow and other items. Based on such limitations, more than $60 million was available for the payment of dividends and other restricted payments at December 31, 1996. Simultaneously with the Acquisition, Patina entered into a bank credit agreement. The agreement consists of (a) a facility provided to Patina and SOCO Wattenberg (the "Patina Facility") and (b) a facility provided to GOG (the "GOG Facility"). The Patina Facility is a revolving credit facility in an aggregate amount up to $102 million. The amount available for borrowing under the Patina Facility will be limited to a semiannually adjusted borrowing base that equaled $85 million at December 31, 1996. At December 31, 1996, $67.5 million was outstanding under the Patina Facility. The GOG Facility is a revolving credit facility in an aggregate amount up to $51 million. The amount available for borrowing under the GOG Facility will be limited to a fluctuating borrowing base that equaled $35 million at December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the GOG Facility. The GOG Facility was used primarily to refinance GOG's previous bank credit facility and pay for costs associated with the Acquisition. The borrowers may elect that all or a portion of the credit facilities bear interest at a rate per annum equal to: (i) the higher of (a) prime rate plus a margin equal to .25% with respect to the GOG Facility and the Patina Facility (the "Applicable Margin") and (b) the Federal Funds Effective Rate plus .5% plus the Applicable Margin, or (ii) the rate at which Eurodollar deposits for one, two, three or six months (as selected by the applicable borrower) are offered in the interbank Eurodollar market in the approximated amount of the requested borrowing (the "Eurodollar Rate") plus 1.25%, with respect to the GOG Facility and the Patina Facility (the "Eurodollar Margin"). During the period subsequent to the Acquisition through December 31, 1996, the average interest rate under the facilities was 6.9%. Patina's bank credit agreement contains certain financial covenants, including but not limited to a maximum total debt to capitalization ratio, a maximum total debt to EBITDA ratio and a minimum current ratio. The bank credit agreement also contains certain negative covenants, including but not limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge clauses; issuance of securities; and non-speculative commodity hedging. 41 Simultaneously with the Acquisition, Patina recorded $100 million of 11.75% Subordinated Notes due July 15, 2004 issued by GOG on July 1, 1994. In connection with the Acquisition, Patina also repurchased $1.2 million of the notes. As part of the purchase accounting, the remaining notes were reflected in the accompanying financial statements at a market value of $104.6 million or 105.875% of their principal amount. Subsequent to the Acquisition, an additional $1.5 million of the notes were repurchased by the Company and retired. Interest is payable each January 15 and July 15. The Notes are redeemable at the option of GOG, in whole or in part, at any time on or after July 15, 1999, initially at 105.875% of their principal amount, declining to 100% on or after July 15, 2001. Upon the occurrence of a change of control, as defined in the Notes, GOG would be obligated to make an offer to purchase all outstanding Notes at a price of 101% of the principal amount thereof. In addition, GOG would be obligated, subject to certain conditions, to make offers to purchase Notes with the net cash proceeds of certain asset sales or other dispositions of assets at a price of 101% of the principal amount thereof. The Notes are unsecured general obligations of GOG and are subordinated to all senior indebtedness of GOG and to any existing and future indebtedness of GOG's subsidiaries. The Notes contain covenants that, among other things, limit the ability of GOG to incur additional indebtedness, pay dividends, engage in transactions with shareholders and affiliates, create liens, sell assets, engage in mergers and consolidations and make investments in unrestricted subsidiaries. Specifically, the Notes restrict GOG from incurring indebtedness (exclusive of the Notes) in excess of approximately $51 million, if after giving effect to the incurrence of such additional indebtedness and the receipt and application of the proceeds therefrom, GOG's interest coverage ratio is less than 2.5:1 or adjusted consolidated net tangible assets are less than 150% of the aggregate indebtedness of GOG. In 1994, SOCO issued $86.3 million of 7% convertible subordinated notes due May 15, 2001. The net proceeds were $83.4 million. The notes are convertible into common stock at $22.57 per share. Given the terms of the notes, common stock dividends not paid out of retained earnings reduce the conversion price when paid. The notes are redeemable at the option of the Company on or after May 15, 1997, initially at 103.51% of principal, and at prices declining to 100% at May 15, 2000. During 1996, the Company repurchased $3.8 million of these notes in accordance with a repurchase program. Scheduled maturities of indebtedness for the next five years are zero for 1997 and 1998, $94.5 million in 1999, $93.7 million in 2000 and $82.5 million in 2001. The long-term portions of the Patina Facilities and SOCO Facility are scheduled to expire in 1999 and 2000. However, it is management's policy to renew both the short-term and long-term facilities and extend their maturities on a regular basis. Consolidated cash payments for interest were $9.9 million, $22.1 million and $21.9 million, respectively, for 1994, 1995 and 1996. (6) STOCKHOLDERS' EQUITY A total of 75 million common shares, $.01 par value, are authorized of which 31.5 million were issued at December 31, 1996. The Company also has 2.1 million warrants outstanding. The warrants are exercisable at a price of $21.04 per share. Under the terms of the warrants, common stock dividends not paid out of retained earnings reduce the exercise price when paid and increase the number of warrants outstanding. Half of the warrants expire in each of February 1998 and February 1999. In 1995, the Company issued 1.2 million shares of common stock, with 1.1 million shares issued in exchange for acquired property interests and 138,000 shares issued primarily for the exercise of stock options. In 1996, the Company issued 666,000 shares of common stock, with 399,000 shares issued in exchange for the remaining outstanding stock of SOCO Offshore and 267,000 shares issued primarily for the exercise of stock options. In 1996, the Company repurchased 725,000 shares of common stock for $7.0 million. Quarterly dividends of $.065 per share were paid in 1995 and 1996. For book purposes, for the period between June 1995 and September 1996, the common stock dividends were in excess of retained earnings and as such were treated as distributions of capital. 42 A total of 10 million preferred shares, $.01 par value, are authorized. In 1993, 4.1 million depositary shares (each representing a quarter interest in a share of $100 liquidation value stock) of 6% preferred stock were sold through an underwriting. The net proceeds were $99.3 million. The stock is convertible into common stock at $20.46 per share. Under the terms of the stock, common stock dividends not paid out of retained earnings reduce the conversion price when paid. The stock is exchangeable at the option of the Company for 6% convertible subordinated debentures on any dividend payment date. The 6% convertible preferred stock is currently redeemable at the option of the Company. The liquidation preference is $25.00 per depositary share, plus accrued and unpaid dividends. At December 31, 1996, the redemption price was $26.05 per depository share. The redemption price declines $.15 per year to $25.00 per depository share in 2003. During 1996, the Company repurchased 6,000 depository shares for $142,000. The Company paid $6.2 million ($1.50 per 6% convertible depositary share per annum) in preferred dividends during both 1995 and 1996. Earnings per share are computed by dividing net income, less dividends on preferred stock, by weighted average common shares outstanding. Net income available (loss applicable) to common for the years ended December 31, 1994, 1995 and 1996, was $1.6 million, ($46.0) million and $56.7 million, respectively. Differences between primary and fully diluted earnings per share were insignificant for all periods presented. The Company maintains a stock option plan for certain employees providing for the issuance of options at prices not less than fair market value. Options to acquire up to three million shares of common stock may be outstanding at any given time. The specific terms of grant and exercise are determined by a committee of independent members of the Board. A stock grant and option plan is also maintained by the Company whereby each nonemployee Director receives 500 common shares quarterly in payment of their annual retainer. It also provides for 2,500 options to be granted annually to each nonemployee Director. The majority of currently outstanding options vest over a three year period (30%, 60%, 100%) and expire five years from the date of grant. At December 31, 1996, the Company has two fixed stock option compensation plans, which are described above. The Company applies APB Opinion No. 25, "Accounting for Stock Issued to Employees", and related Interpretations in accounting for the plans. Accordingly, no compensation cost has been recognized for these fixed stock option plans. Had compensation cost for the Company's fixed stock option compensation plans been determined consistent with SFAS 123, "Accounting for Stock-Based Compensation", the Company's net income (in thousands) and earnings per share would have been reduced to the pro forma amounts indicated below:
1995 1996 --------- --------- Net income (loss) As Reported $ (39,831) $ 62,950 Pro forma $ (40,567) $ 61,936 Income (loss) per share As Reported $ (1.53) $ 1.81 Pro forma $ (1.55) $ 1.78
The fair value of each option grant is estimated on the date of grant using the Black-Sholes option-pricing model with the following weighted-average assumptions used for grants in 1995 and 1996, respectively: dividend yield of 1.9% and 2.8%; expected volatility of 46% and 44%; risk-free interest rates of 7.2% and 5.7%; and an expected life of 4.5 years. 43 A summary of the status of the Company's two fixed stock option plans as of December 31, 1994, 1995 and 1996 and changes during the years ended on those dates is presented below (shares are in thousands):
1994 1995 1996 --------------------- --------------------- --------------------- WEIGHTED- WEIGHTED- WEIGHTED- AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE ------ --------- ------ --------- ------ --------- Outstanding at beginning of year 1,383 $5.66 1,484 $12.96 1,711 $13.21 Granted 510 18.38 610 14.06 519 9.50 Exercised (407) 5.35 (124) 7.34 (255) 6.69 Forfeited (2) 16.14 (259) 16.62 (301) 14.71 ------ ------ ------ Outstanding at end of year 1,484 12.96 1,711 13.21 1,674 12.72 ====== ====== ====== Options exercisable at year end 533 743 772 Weighted-average fair value of options granted during the year N/A $5.78 $3.27
The following table summarizes information about fixed stock options outstanding at December 31, 1996:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------------------------ ------------------------------- NUMBER WEIGHTED- NUMBER RANGE OUTSTANDING AT AVERAGE WEIGHTED- EXERCISABLE AT WEIGHTED- OF DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE EXERCISE PRICES 1996 CONTRACTUAL LIFE EXERCISE PRICE 1996 EXERCISE PRICE (In years) - ------------------- -------------- ---------------- -------------- -------------- -------------- $ 6.00 to 8.88 163,000 0.9 $ 6.09 163,000 $ 6.09 9.38 to 13.75 771,000 3.3 10.85 260,000 13.02 14.13 to 20.13 740,000 2.6 16.14 349,000 16.98 --------- ------- $ 6.00 to 20.13 1,674,000 2.7 12.72 772,000 13.35 ========= =======
(7) FEDERAL INCOME TAXES At December 31, 1996, the Company had no liability for foreign taxes. A reconciliation of the United States federal statutory rate to the Company's effective income tax rate for the years ended December 31, 1994, 1995 and 1996 follows:
1994 1995 1996 -------- -------- -------- Federal statutory rate 35% (35%) 35% Loss in excess of net deferred tax liability - 32% - Net change in valuation allowance (27%) - (29%) Alternative minimum taxes (1%) - - ------- ------- ------- Effective income tax rate 7% (3%) 6% ======= ======= =======
44 For book purposes, the components of the net deferred tax asset and liability at December 31, 1995 and 1996, respectively, were:
1995 1996 ----------- ----------- Deferred tax assets NOL and capital loss carryforwards $ 53,010 $ 65,126 AMT credit carryforwards 1,293 644 Production payment receivables - 32,654 Reserves and other 1,977 5,613 ----------- ----------- 56,280 104,037 ----------- ----------- Deferred tax liabilities Depreciable and depletable property (24,018) (59,865) Investments and other (2,171) (42,252) Unrealized investments gains (317) (7,131) ----------- ----------- (26,506) (109,248) ----------- ----------- Deferred asset (liability) 29,774 (5,211) Valuation allowance (29,774) (3,823) ----------- ----------- Net deferred tax liability $ - $ (9,034) =========== ===========
For tax purposes, Patina is not included in the Company's consolidated United States federal income tax return. The Company, excluding Patina, had regular net operating loss carryforwards of $112 million and alternative minimum tax loss carryforwards of $28.9 million at December 31, 1996. These carryforwards expire between 1997 and 2010. At December 31, 1996, the Company, excluding Patina, had long-term capital loss carryforwards of $3.9 million which will expire in 2000. At December 31, 1996, the Company, excluding Patina, also had alternative minimum tax credit carryforwards of $644,000 which are available indefinitely. Patina had regular net operating loss carryforwards of $70.2 million and alternative minimum tax loss carryforwards of $35.1 million at December 31, 1996. Utilization of $31.9 million regular net operating loss carryforwards and $31.6 million alternative minimum tax loss carryforwards will be limited to $5.2 million per year as a result of the Acquisition. These carryforwards expire from 2006 through 2011. At December 31, 1996, Patina had alternative minimum tax credit carryforwards of $478,000 which are available indefinitely. Current income taxes shown in the financial statements reflect estimates of alternative minimum taxes. (8) MAJOR CUSTOMERS In 1994 and 1995, Amoco Production Company accounted for approximately 11% and 10%, respectively, of revenues. In 1996, Pan Energy accounted for approximately 11% of revenues. Management believes that the loss of any individual purchaser would not have a material adverse impact on the financial position or results of operations of the Company. (9) COMMITMENTS AND CONTINGENCIES The Company rents offices at various locations under noncancelable operating leases. Minimum future payments under such leases approximate $2.5 million for 1997, $2.4 million for 1998, $2.6 million for 1999, $2.6 million for 2000 and $1.6 million for 2001. In August 1995, the Company was sued in the United States District Court of Colorado by seven plaintiffs purporting to represent all persons who, at any time since January 1, 1960, have had agreements providing for royalties from gas production in Colorado to be paid by the Company under a number of various lease provisions. In January 1997, the judge ordered that the class not be certified. All remaining liability under this suit was assumed by Patina upon its formation. In January 1996, GOG was also sued in a similar but separate class action filed in stated court. In both suits, the plaintiffs allege that unspecified "post-production" costs incurred prior to calculating royalty payments were deducted in breach of the relevant lease provisions and that this 45 fact was fraudulently concealed. The plaintiffs seek unspecified compensatory and punitive damages and a declaratory judgment prohibiting deduction of post-production costs prior to calculating royalties paid to the class. The Company believes that calculations of royalties by it and GOG are and have been proper under the relevant lease provisions, and intends to defend these and any similar suits vigorously. In September 1996, the Company and other interest owners in a lease in southern Texas were sued by the royalty owners in Texas state court in Brooks County, Texas. The Company's working interest in the lease is approximately 20%. The complaint alleges, among other things, that the defendants have failed to pay proper royalties under the lease and have breached their duties to reasonably develop the lease. The plaintiffs also claim damages for fraud and trespass, and demand actual and punitive damages. Although the complaint does not specify the amount of damages claimed, an earlier letter from plaintiffs claimed damages in excess of $50 million. The Company and the other interest owners have filed an answer denying the claims and intend to contest the suit vigorously. At this time, the Company is unable to estimate the range of potential loss, if any, from the foregoing uncertainties. However, the Company believes their resolution should not have a material adverse effect upon the Company's financial position, although an unfavorable outcome in any reporting period could have a material impact on the Company's results of operations for that period. In April 1995, the Company settled a lawsuit in Harris County, Texas filed by certain landowners relating to certain alleged problems at a Company well site. The Company recorded a charge of $4.4 million during the first quarter of 1995 to reflect the cost of the settlement. A primary insurer honored its commitments in full and participated in the settlement. The Company's excess carriers have declined, to date, to honor indemnification for the loss. Based on the advice of counsel, the Company has brought suit against the non-participating carriers for the great majority of the cost of settlement. However, given the time period which may be involved in resolving the matter, the full amount of the settlement was provided for in the financial statements. In the second quarter of 1996, the Company received $1.5 million in proceeds which was reflected in other income related to a judgment involving a pipeline dispute. The Company's operations are affected by political developments and federal and state laws and regulations. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic and other reasons. Numerous departments and agencies, federal, state, local and Indian, issue rules and regulations binding on the oil and gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases the Company's cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects. The financial statements reflect favorable legal proceedings only upon receipt of cash, final judicial determination or execution of a settlement agreement. The Company is a party to various other lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations. (10) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION Independent petroleum consultants directly evaluated 58%, 81%, and 99% of proved reserves at December 31, 1994, 1995 and 1996, respectively, and performed a detailed review of properties which comprised in excess of 80% of proved reserve value in 1994. All reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year end were computed by applying then current prices to estimated future production less estimated future expenditures (based on current costs) to be incurred in producing and developing the reserves. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain 46 constant. With respect to certain properties that historically have experienced seasonal curtailment, the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the tables below represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown below. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered. All reserves included in the tables below are located onshore in the United States and in the waters of the Gulf of Mexico.
QUANTITIES OF PROVED RESERVES - CRUDE OIL NATURAL GAS --------- ----------- (MBBL) (MMCF) Balance, December 31, 1993 31,930 430,089 Revisions (296) (102,871) Extensions, discoveries and additions 3,981 136,583 Production (4,366) (43,809) Purchases 3,866 93,334 Sales (138) (2,075) -------- -------- Balance, December 31, 1994 34,977 511,251 Revisions (3,633) (89,455) Extensions, discoveries and additions 782 32,835 Production (4,278) (53,227) Purchases 2,002 13,449 Sales (5,603) (19,135) -------- -------- Balance, December 31, 1995 24,247 395,718 Revisions 4,127 41,385 Extensions, discoveries and additions 1,039 61,821 Production (3,884) (55,840) Purchases 16,725 225,335 Sales (1,757) (62,783) -------- -------- Balance, December 31, 1996 40,497 605,636 ======== ========
The table above includes reserves attributable to minority interests of 18.6 million BOE at December 31, 1996. The Company's interest in the Russian joint venture (Permtex) is accounted for under the equity method. At December 31, 1994, 1995 and 1996, the Company's equity in Permtex proved reserves was 8.0 million BOE, 7.8 million BOE and 8.6 million BOE, respectively. These amounts are not included in the quantities above. 47
PROVED DEVELOPED RESERVES - CRUDE NATURAL OIL GAS --------- --------- (MBBL) (MMCF) December 31, 1993 18,032 268,349 ========= ========= December 31, 1994 26,104 353,930 ========= ========= December 31, 1995 21,637 330,524 ========= ========= December 31, 1996 31,869 443,441 ========= =========
STANDARDIZED MEASURE - DECEMBER 31, ---------------------------- 1995 1996 ----------- ----------- (IN THOUSANDS) Future cash inflows $ 1,037,363 $ 3,144,813 Future costs: Production (374,516) (781,550) Development (57,959) (233,617) ----------- ----------- Future net cash flows 604,888 2,129,646 Undiscounted income taxes (63,248) (540,520) ----------- ----------- After tax net cash flows 541,640 1,589,126 10% discount factor (210,534) (650,534) ----------- ----------- Standardized measure $ 331,106 $ 938,592 =========== ===========
The table above includes standardized measure attributable to minority interests of $129.5 million at December 31, 1996. At December 31, 1995 and 1996, the Company's equity in the net present value of Permtex proved reserves was $10.6 million and $25.8 million. These amounts are not included in the standardized measure above. 48
CHANGES IN STANDARDIZED MEASURE - YEAR ENDED DECEMBER 31, ------------------------------------------------ 1994 1995 1996 ----------- ----------- ----------- (IN THOUSANDS) Standardized measure, beginning of year $ 340,518 $ 361,682 $ 331,106 Revisions: Prices and costs (73,330) 18,975 528,525 Quantities (42,260) (30,495) 10,915 Development costs (12,995) (2,806) (13,027) Accretion of discount 34,052 36,168 46,045 (a) Income taxes 2,195 16,249 (242,536) Production rates and other (9,506) (29,991) 11,052 ----------- ----------- ----------- Net revisions (101,844) 8,100 340,974 Extensions, discoveries and additions 68,002 18,171 111,797 Production (97,330) (96,232) (146,257) Future development costs incurred 99,175 43,551 18,400 Purchases 55,072 31,142 330,225 (a) Sales (1,911) (35,308) (47,653) ----------- ----------- ----------- Standardized measure, end of year $ 361,682 $ 331,106 $ 938,592 =========== =========== =========== (a) In 1996, $12.9 million in "Purchases" were included in "Accretion of Discount" due to the significance of the accretion related to the reserves purchased in the Acquisition.
49 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. (a) 1. Reference is made to Item 8 on page 28. 2. Schedules otherwise required by Item 8 have been omitted as not required or not applicable. 3. Exhibits. 4.1.1 - Certificate of Incorporation of Registrant -- incorporated by reference from Exhibit 3.1 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455) 4.1.2 - Certificate of Amendment to Certificate of Incorporation of Registrant filed February 9, 1990 -- incorporated by reference from Exhibit 3.1.1 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455). 4.1.3 - Certificate of Amendment to Certificate of Incorporation of Registrant filed May 22, 1991 -- incorporated by reference from Exhibit 3.1.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-43106). 4.1.4 - Certificate of Amendment to Certificate of Incorporation of Registrant filed May 24, 1993 -- incorporated by reference from Exhibit 3.1.5 to the Registrant's Form 10-Q for the quarter-ended June 30, 1993 (File No. 1-10509). 4.1.5 - Indenture dated as of May 1, 1994 between the Registrant and Texas Commerce Bank National Association relating to Registrant's 7% Convertible Subordinated Notes due 2001 -- incorporated by reference from Exhibit 4.1.5 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 (File No. 1-10509). 4.1.6 - Certificate of Designations of the Registrant's $6.00 Convertible Exchangeable Preferred Stock -- incorporated by reference from Exhibit 3.1.5 to the Registrant's Form 10-Q for the quarter-ended June 30, 1993 (File No. 1-10509) 10.1 - Snyder Oil Corporation 1990 Stock Option Plan for Non-Employee Directors -- incorporated by reference from Exhibit 10.4 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455). 10.1.1 - Amendment dated May 20, 1992 to the Registrant's 1990 Stock Plan for Non-Employee Directors -- incorporated by reference from Exhibit 10.1.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter-ended June 30, 1993 (File No. 1-10509). 10.2 - Registrant's Restated 1989 Stock Option Plan -- incorporated by reference from Exhibit 10.2.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter-ended June 30, 1992 (File No. 1- 10509). 10.3 - Registrant's Deferred Compensation Plan for Select Employees, adopted effective June 1, 1994 -- incorporated by reference from Exhibit 10.3 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 (File No. 1-10509) 10.4 - Registrant's Profit Sharing & Savings Plan and Trust as amended and restated effective October 1, 1993 -- incorporated by reference from Exhibit 10.12 to the Registrant's Quarterly Report on Form 10-Q for the quarter-ended September 30, 1993 (File No. 1-10509). 50 10.5 - Form of Indemnification Agreement -- incorporated by reference from Exhibit 10.15 to the Registrant's Registration Statement on Form S-4 (Registration No. 33-33455). 10.6 - Form of Change in Control Protection Agreement -- incorporated by reference from Exhibit 10.11 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-43106). 10.7 - Long-term Retention and Incentive Plan and Agreement between the Registrant and Charles A. Brown -- incorporated by reference from Exhibit 10.1.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter-ended June 30, 1993 (File No. 1-10509). 10.8 - Agreement dated as of April 30, 1993 between the Registrant and Edward T. Story -- incorporated by reference from Exhibit 10.8 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 1-10509). 10.9 - Formation and Capitalization Agreement dated as of December 30, 1996 among Registrant, SOCO International, Inc., SOCO International Holdings, Inc., SOCO International Operations, Inc. and Edward T. Story.* 10.9.1 - Promissory Note dated December 30, 1996 from Edward T. Story payable to the order of SOCO International Holdings, Inc.* 10.9.2 - Promissory Note dated December 30, 1996 from Edward T. Story payable to the order of SOCO International Operations, Inc.* 10.10 - Warrant dated February 8, 1994 issued by Registrant to Union Pacific Resources Company -- incorporated by reference from Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 1-10509). 10.11 - Fifth Restated Credit Agreement dated as of June 30, 1994 among the Registrant and the banks party thereto -- incorporated by reference from Exhibit 10.11 to the Registrant's Quarterly Report on Form 10-Q for the quarter-ended June 30, 1994 (File No. 1-10509). 10.11.1 - First Amendment dated as of May 1, 1995 to Fifth Restated Credit Agreement -- incorporated by reference from Exhibit 10.11.1 to Registrant's Quarterly Report on Form 10-Q for the quarter-ended June 30, 1995 (File No. 1-10509). 10.11.2 - Second Amendment dated as of June 30, 1995 to Fifth Restated Credit Agreement -- incorporated by reference from Exhibit 10.12.2 to Registrant's Quarterly Report on Form 10-Q for the quarter- ended June 30, 1995 (File No. 1-10509). 10.11.3 - Third Amendment dated as of November 1, 1995 to Fifth Restated Credit Agreement -- incorporated by reference from Exhibit 10.11.3 to Registrant's Annual Report on Form 10-K of the year ended December 31, 1995 (File No. 1-10509). 10.11.4 - Fourth Amendment dated as of April 4, 1996 to Fifth Restated Credit Agreement -- incorporated by reference to Registrant's Quarterly Report on Form 10-Q for the quarter-ended March 31, 1996 (File No. 1-10509). 10.11.5 - Fifth Amendment dated as of November 1, 1996 to Fifth Restated Credit Agreement.* 10.12 - Severance Agreement and Release dated November 14, 1995 between Registrant and John A. Fanning -- incorporated by reference from Exhibit 10.12 to Registrant's Annual Report on Form 10-K of the year ended December 31, 1995 (File No. 1-10509). 51 10.13 - Amended and Restated Agreement and Plan of Merger dated as of March 20, 1996 among Registrant, Patina Oil & Gas Corporation, Patina Merger Corporation and Gerrity Oil & Gas Corporation -- incorporated by reference from Exhibit 2.1 to Amendment No. 1 to the Registration Statement on Form S-4 of Patina Oil & Gas Corporation (Registration No. 333-572). 11.1 - Computation of Per Share Earnings.* 12 - Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.* 22.1 - Subsidiaries of the Registrant.* 23.1 - Consent of Arthur Andersen LLP.* 23.2 - Consent of Netherland, Sewell & Associates, Inc.* 23.3 - Consent of Ryder Scott Company Petroleum Engineers.* 27 - Financial Data Schedule.* 99.1 - Reserve letter from Netherland, Sewell & Associates, Inc. dated February 5, 1997 to the Snyder Oil Corporation interest as of December 31, 1996* 99.2 - Reserve letter from Netherland, Sewell & Associates, Inc. dated February 5, 1997 to the Patina Oil & Gas Corporation interest as of December 31, 1996* 99.3 - Reserve letter from Ryder Scott Company Petroleum Engineers dated February 5, 1997 to the SOCO Offshore, Inc. interest as of December 31, 1996* (b) No reports on Form 8-K in the fourth quarter of 1996. * Filed herewith. 52 SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. /S/ JOHN C. SNYDER Director and Chairman of the Board March 10, 1997 - ------------------------ (Principal Executive Officer) John C. Snyder /S/ ROGER W. BRITTAIN Director March 10, 1997 - ------------------------ Roger W. Brittain /S/ JOHN A. HILL Director March 10, 1997 - ------------------------ John A. Hill /S/ WILLIAM J. JOHNSON Director March 10, 1997 - ------------------------ William J. Johnson /S/ B. J. KELLENBERGER Director March 10, 1997 - ------------------------ B. J. Kellenberger /S/ JAMES E. MCCORMICK Director March 10, 1997 - ------------------------ James E. McCormick /S/ ALFRED M. MICALLEF Director March 10, 1997 - ------------------------ Alfred M. Micallef /S/ EDWARD T. STORY Director and March 10, 1997 - ------------------------ Vice President - International Edward T. Story /S/ JAMES H. SHONSEY Vice President - Finance March 10, 1997 - ------------------------ (Principal Financial and James H. Shonsey Accounting Officer) 53 SCHEDULE I SNYDER OIL CORPORATION (PARENT COMPANY) CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
DECEMBER 31, ------------------------------- 1995 1996 ------------ ------------ ASSETS Current assets Cash and equivalents $ 27,263 $ 21,769 Accounts receivable 29,259 38,968 Inventory and other 11,769 9,755 ------------ ------------ 68,291 70,492 ------------ ------------ Investments 33,220 245,610 ------------ ------------ Oil and gas properties, successful efforts method 675,961 328,649 Accumulated depletion, depreciation and amortization (240,744) (91,902) ------------ ------------ 435,217 236,747 ------------ ------------ Gas facilities and other 30,506 16,558 Accumulated depreciation and amortization (11,741) (4,251) ------------ ------------ 18,765 12,307 ------------ ------------- $ 555,493 $ 565,156 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 36,353 $ 36,804 Accrued liabilities 26,096 25,534 ------------ ------------ 62,449 62,338 ------------ ------------ Senior debt 150,001 93,731 Convertible subordinated notes 84,058 80,748 Deferred taxes payable - 9,034 Other noncurrent liabilities 20,016 18,233 Minority interest 3,601 6,404 Commitments and contingencies Stockholders' equity Preferred stock, $.01 par, 10,000,000 shares authorized, 6% Convertible preferred stock, 1,035,000 and 1,033,500 shares issued and outstanding 10 10 Common stock, $.01 par, 75,000,000 shares authorized, 31,430,227 and 31,456,027 issued 314 315 Capital in excess of par value 265,911 260,221 Retained earnings (deficit) (29,001) 25,711 Common stock held in treasury, 134,191 and 250,000 shares at cost (2,457) (3,510) Unrealized foreign currency translation gain 380 - Unrealized gain on investments 211 11,921 ------------ ------------ 235,368 294,668 ------------ ------------ $ 555,493 $ 565,156 ============ ============ See "Notes to Consolidated Financial Statements" of the Snyder Oil Corporation Consolidated Financial Statements included in this report.
54 SCHEDULE I SNYDER OIL CORPORATION (PARENT COMPANY) CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, -------------------------------------------- 1994 1995 1996 ---------- ---------- ---------- Revenues Oil and gas sales $ 137,858 $ 144,608 $ 121,967 Gas transportation, processing and marketing 107,247 38,256 17,655 Gains on sales of equity interests in investees 9,747 2,183 69,343 Gains on sales of properties 1,969 12,254 8,786 Equity in earnings of Patina - - 1,554 Other 5,507 4,859 6,320 --------- --------- --------- 262,328 202,160 225,625 --------- --------- --------- Expenses Direct operating 46,267 52,486 37,736 Cost of gas and transportation 94,177 29,374 15,020 Exploration 6,505 8,033 4,094 General and administrative 12,853 17,680 13,129 Interest and other 12,463 27,001 16,218 Litigation settlement - 4,400 - Loss on sale of subsidiary interest - - 15,481 Depletion, depreciation and amortization 70,770 76,378 49,032 Property impairments 5,783 27,412 2,753 --------- --------- --------- Income (loss) before taxes and minority interest 13,510 (40,604) 72,162 --------- --------- --------- Provision (benefit) for income taxes Current - 25 33 Deferred 967 (1,370) 4,313 --------- --------- --------- 967 (1,345) 4,346 --------- --------- --------- Minority interest (171) (572) (4,866) --------- --------- --------- Net income (loss) $ 12,372 $ (39,831) $ 62,950 ========= ========= ========= Net income (loss) per common share $ .07 $ (1.53) $ 1.81 ========= ========= ========= Weighted average shares outstanding 23,704 30,186 31,308 ========= ========= ========= See "Notes to Consolidated Financial Statements" of the Snyder Oil Corporation Consolidated Financial Statements included in this report.
55 SCHEDULE I SNYDER OIL CORPORATION (PARENT COMPANY) CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, --------------------------------------------- 1994 1995 1996 ----------- ----------- ----------- Operating activities Net income (loss) $ 12,372 $ (39,831) $ 62,950 Adjustments to reconcile net income (loss) to net cash provided by operations Amortization of deferred credits (2,986) (2,511) (966) Gains on sales of investments (9,747) (809) (68,343) Gains on sales of properties (1,969) (12,254) (8,786) Equity in (earnings) losses of unconsolidated subsidiaries (1,355) 1,319 (1,975) Exploration expense 6,505 8,033 4,094 Loss on sale of subsidiary interest - - 15,481 Depletion, depreciation and amortization 70,770 76,378 49,032 Property impairments 5,783 27,412 2,753 Deferred taxes 967 (1,370) 4,313 Minority interest 171 572 4,866 Changes in current and other assets and liabilities Decrease (increase) in Accounts receivable 11,024 7,142 (12,025) Inventory and other (9,241) 3,617 3,583 Increase (decrease) in Accounts payable 1,901 (8,521) 4,502 Accrued liabilities 1,841 5,165 (69) Other liabilities 361 4,779 (346) ----------- ----------- ----------- Net cash provided by operations 86,397 69,121 59,064 ----------- ----------- ----------- Investing activities Acquisition, development and exploration (237,879) (92,353) (93,368) Purchase of controlling interest in subsidiary (6,645) - - Proceeds from investments 5,019 14,786 1,635 Outlays for investments (8,804) - (9,013) Proceeds from sales of properties 2,806 109,988 72,510 ----------- ----------- ----------- Net cash realized (used) by investing (245,503) 32,421 (28,236) ----------- ----------- ----------- Financing activities Issuance of common 1,157 688 1,523 Increase (decrease) in indebtedness 187,138 (86,193) (12,814) Debt issuance costs (2,855) - - Dividends (16,721) (14,056) (14,411) Deferred credits 2,356 3,549 62 Repurchase of stock (1,149) - (7,186) Repurchase of subordinated notes - - (3,496) ----------- ----------- ----------- Net cash realized (used) by financing 169,926 (96,012) (36,322) ----------- ----------- ----------- Increase in cash 10,820 5,530 (5,494) Cash and equivalents, beginning of year 10,913 21,733 27,263 ----------- ----------- ----------- Cash and equivalents, end of year $ 21,733 $ 27,263 $ 21,769 =========== =========== =========== Noncash investing and financing activities Gas plant capital lease $ 21,000 - - Acquisition of properties and stock via stock issuances - $ 13,032 $ 3,693 Acquisition of properties recorded as senior debt - - $ 31,730 Acquisition via subsidiary stock issuance - - $ 115,067 See "Notes to Consolidated Financial Statements" of the Snyder Oil Corporation Consolidated Financial Statements included in this report.
56 EX-10 2 FORMATION AND CAPITALIZATION AGREEMENT EXHIBIT 10.9 FORMATION AND CAPITALIZATION AGREEMENT This Formation and Capitalization Agreement (this "Agreement") is entered into as of the 30th day of December, 1996 by and between Snyder Oil Corporation, a Delaware corporation ("Snyder"), SOCO International, Inc., a Delaware corporation ("SOCO International"), SOCO International Holdings, Inc., a Delaware corporation ("Holdings"), SOCO International Operations, Inc., a Delaware corporation ("Operations") and Edward T. Story, Jr., a resident of the State of Texas ("Story"). WHEREAS, SOCO International is a wholly owned subsidiary of Snyder; WHEREAS, SOCO International has recently incorporated and organized Operations and Holdings as wholly-owned subsidiaries of SOCO International; WHEREAS, SOCO International owns beneficially and of record one share of the common stock of Operations ("Operations Common Stock") and one share of the common stock of Holdings ("Holdings Common Stock"); WHEREAS, pursuant to that certain agreement by and between Snyder and Story dated as of April 30, 1993 (the "1993 Agreement"), Story holds a non-compensatory option (the "Option") to acquire 100 shares of common stock (10% of the then outstanding shares) of SOCO International, which Option was received in exchange for common stock of SOCO International then held by Story; WHEREAS, Story and International desire to capitalize Operations and Holdings by contributing the assets described herein to such corporations in the manner set forth herein, subject to the assumption of the liabilities described herein; NOW THEREFORE, in consideration of the premises set forth above, the mutual covenants set forth herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows: 1. DEFINITIONS. (a) "EFFECTIVE TIME" shall mean 9:00 a.m. (Houston time) on the date first set forth above. (b) "CAIRN SHARES" shall mean the shares of capital stock of Cairn Energy Plc owned beneficially or of record by SOCO International immediately prior to the Effective Time. (c) "HOLDINGS ASSETS" shall mean SOCO International's right, title and interest in any rights, privileges, powers, franchises, properties or assets related to the Cairn Shares, (including any dividends and distributions with respect thereto) immediately prior to the Effective Time. (d) "OPERATIONS ASSETS" shall mean SOCO International's right, title and interest in any rights, privileges, powers, franchises, properties or assets immediately prior to the Effective Time, but specifically excluding the Holdings Assets. 1 (e) "LIABILITIES" shall mean all losses, claims, taxes, fines, penalties, damages, costs (including costs of investigation) expenses (including reasonable legal fees and expenses) and other liabilities, whether joint or several. (f) "INTERCOMPANY DEBT" shall mean the intercompany indebtedness owed by SOCO International to Snyder as of the Effective Time, which had a balance of $34,504,390 as of November 30, 1996. (g) "HOLDINGS LIABILITIES" shall mean SOCO International's Liabilities related to the Holdings Assets and (ii) the Intercompany Debt. (h) "OPERATIONS LIABILITIES" shall mean SOCO International's Liabilities relating to the Operations Assets, but specifically excluding the Holdings Liabilities. (i) "SOCO INTERNATIONAL INDEMNIFIED PARTIES" shall mean SOCO International and its subsidiaries (other than Operations, Holdings and their respective subsidiaries) and any officer, director, employee, agent or other representative thereof (individually, a "SOCO International Indemnified Party"). (j) "OPERATIONS INDEMNIFIED PARTIES" shall mean Operations and its subsidiaries and any officer, director, employee, agent or other representative thereof (individually, an "Operations Indemnified Party"). (k) "HOLDINGS INDEMNIFIED PARTIES" shall mean Holdings and its subsidiaries and any officer, director, employee, agent or other representative thereof (individually, an "Holdings Indemnified Party"). 2. CAPITALIZATION OF OPERATIONS. (a) Effective as of the Effective Time, SOCO International and Story hereby contribute to Operations the assets described in paragraphs (b) and (c) hereof, respectively. In consideration for such contributions, Operations hereby issues shares of Operations Common Stock to SOCO International and Story in the respective amounts set forth below:
TOTAL SHARES OF OPERATIONS SHARES OF OPERATIONS SHARES OF OPERATIONS COMMON STOCK OWNED COMMON STOCK COMMON STOCK TO BE IMMEDIATELY FOLLOWING SHAREHOLDER CURRENTLY OWNED ISSUED AT EFFECTIVE TIME EFFECTIVE TIME - ----------- --------------- ------------------------ --------------------- SOCO 1 899 900 International Story 0 100 100 - --- ----- Total 1 999 1,000 = === =====
(b) Effective as of the Effective Time, (i) SOCO International hereby transfers, sells, assigns, bargains and conveys to Operations all of SOCO International's right, title and interest in the Operations Assets, and (ii) Operations hereby assumes all of the Operations Liabilities. (c) Effective as of the Effective Time, Story hereby (i) transfers, sells, assigns, bargains and conveys to Operations such portion of Story's right, title and interest in the Option as it relates 2 to the right to purchase 45.65 shares of the common stock of SOCO International (together with 45.65% of Story's remaining rights under the 1993 Agreement), and (ii) delivers to Operations a recourse promissory note from Story in the principal amount of $269,563.25 and substantially in the form attached hereto as Exhibit A (the "Operations Note"). (d) Effective as of the Effective Time, Operations hereby delivers to International and Story certificates for the shares of Operations Common Stock issued pursuant to this Section 2. 3. CAPITALIZATION OF HOLDINGS. (a) Effective as of the Effective Time, SOCO International and Story hereby contribute to Holdings the assets described in paragraphs (b) and (c) hereof, respectively. In consideration for such contributions, Holdings hereby issues shares of Holdings Common Stock to SOCO International and Story in the respective amounts set forth below: TOTAL SHARES OF HOLDINGS SHARES OF HOLDINGS SHARES OF HOLDINGS COMMON STOCK OWNED COMMON STOCK COMMON STOCK TO BE IMMEDIATELY FOLLOWING SHAREHOLDER CURRENTLY OWNED ISSUED AT EFFECTIVE TIME EFFECTIVE TIME - ----------- --------------- ------------------------ --------------------- SOCO International 1 899 900 Story 0 100 100 - --- ----- Total 1 999 1,000 = === =====
(b) Effective as of the Effective Time, (i) SOCO International hereby transfers, sells, assigns, bargains and conveys to Holdings all of SOCO International's right, title and interest in all of the Holdings Assets, and (ii) Holdings hereby assumes the Holdings Liabilities. (c) Effective as of the Effective Time, Story hereby (i) transfers, sells, assigns, bargains and conveys to Holdings such portion of Story's right, title and interest in the Option as it relates to the right to purchase 54.35 shares of the common stock of SOCO International (together with 54.35% of Story's remaining rights under the 1993 Agreement), and (ii) delivers to Holdings a recourse promissory note from Story in the principal amount of $320,936.75 and substantially in the form attached hereto as Exhibit A (the "Holdings Note"). The parties hereto acknowledge that after the transfer of the Option pursuant to Sections 2(c) and 3(c) hereof, Story shall have no further rights under the Option or the 1993 Agreement, and all such rights shall be transferred to Operations and Holdings in the respective amounts set forth herein. In accordance with paragraph 8 of the 1993 Agreement, Snyder hereby consents to the assignments of the Option contemplated by this Agreement. (d) Effective as of the Effective Time, Holdings hereby delivers to International and Story certificates for the shares of Holdings Common Stock issued pursuant to this Section 3. 4. INDEMNIFICATION. (a) Operations shall defend, indemnify and hold harmless the SOCO International Indemnified Parties and the Holdings Indemnified Parties against any and all Operations Liabilities, whether or not the result of the sole or partial negligence or otherwise culpable conduct or fault of one or more of the SOCO International Indemnified Parties or the Holdings Indemnified Parties. 3 (b) Holdings shall defend, indemnify and hold harmless the SOCO International Indemnified Parties and the Operations Indemnified Parties against any and all Holdings Liabilities, whether or not the result of the sole or partial negligence or otherwise culpable conduct or fault of one or more of the SOCO International Indemnified Parties or the Operations Indemnified Parties. 5. INDEMNIFICATION PROCEDURE. Each person to be indemnified pursuant to this Agreement (an "Indemnified Party") agrees to give prompt notice to the indemnifying party of the assertion of any claim, or the commencement of any suit, action or proceeding, brought against or sought to be collected from such Indemnified Party (each a "Third Party Claim"), in respect of which indemnity may be sought by such Indemnified Party under this Agreement; provided that the omission so to promptly notify the indemnifying party with respect to a Third Party Claim brought against or sought to be collected from such Indemnified Party will not relieve the indemnifying party from any Liability that it may have to such Indemnified Party under this Agreement except to the extent that such failure has materially prejudiced such indemnifying party with respect to the defense of such Third Party Claim. If any Indemnified Party shall seek indemnity under this Agreement with respect to a Third Party Claim brought against or sought to be collected from such Indemnified Party, the indemnifying party shall be entitled to participate therein and, to the extent that it wishes, to assume and direct the defense and settlement thereof with counsel satisfactory to such Indemnified Party. After notice from the indemnifying party to an Indemnified Party of its election to assume and direct the defense and settlement of a Third Party Claim brought against or sought to be collected from such Indemnified Party that such indemnifying party is entitled to assume and direct under the terms hereof, the indemnifying party shall not be liable to such Indemnified Party under this Agreement for any legal or other expenses subsequently incurred by such Indemnified Party in connection with the defense thereof other than reasonable costs of investigation, unless the Indemnifying Party and the Indemnified Party are both named parties to any such action, claim or demand and representation of both parties by the same counsel would be inappropriate due to actual or potential conflicts of interest between them. Notwithstanding the foregoing provisions of this Section 5, the indemnifying party shall not (A) without the prior written consent of an Indemnified Party, effect any settlement of any pending or threatened proceeding in respect of which such Indemnified Party is, or with reasonable foreseeability, could have been a party and indemnity could have been sought hereunder by such Indemnified Party for a Third Party Claim brought against or sought to be collected from such Indemnified Party, unless such settlement includes an unconditional release, in form and substance satisfactory to the Indemnified Party, of such Indemnified Party from all Liability arising out of such proceeding (provided that, whether or not such a release is required to be obtained, the indemnifying party shall remain liable to such Indemnified Party in accordance with this Agreement in the event that a Third Party Claim is subsequently brought against or sought to be collected from such Indemnified Party) or (B) be liable for any settlement of any Third Party Claim brought against or sought to be collected from an Indemnified Party effected without such indemnifying party's written consent (which shall not be unreasonably withheld), but if settled with such indemnifying party's written consent, or if there is a final judgment for the plaintiff in any such Third Party Claim, such indemnifying party agrees (to the extent stated above) to indemnify the Indemnified Party from and against any loss, liability, claim, damage or expense by reason or such settlement or judgment. The indemnification required by this Agreement shall be made by payments of the amount thereof during the course of the investigation or defense, as and when bills are received or loss, liability, claim, damage or expense is incurred. 4 6. REPRESENTATIONS. In order to induce each other party to enter into this Agreement, each party hereto hereby represents and warrants to each other party hereto that (a) this Agreement has been duly authorized by such party by all necessary corporate action (to the extent such party is a corporation), (b) such party has the legal capacity to enter into this Agreement (to the extent such party is an individual), (c) the performance by such party of the obligations contemplated hereby to be performed by such party do not conflict with the organizational documents (to the extent such party is a corporation) or any agreement, judgment, order, law, regulation, rule or instrument to which such party is subject. Without limiting the generality of the foregoing, Snyder and Story each represent that the 1993 Agreement and the Option granted therein are in full force and effect, that such party is not in breach thereof and that such party has not assigned or transferred any rights thereunder, or attempted to do so, except as expressly contemplated by this Agreement. 7. SECURITIES LAW MATTERS. SOCO International and Story represent to each other and to Operations and Holdings that they are knowledgeable and sophisticated investors with respect to the type of business to be conducted by Operations and Holdings and that they have had access to such information as they have requested in connection therewith. SOCO International and Story acknowledge that the shares of Operations Common Stock and Holdings Common Stock received by them will not be registered under the federal or any state securities laws, that no party shall have any obligation to register such shares, and that no sale, transfer or other disposition of such shares may be made without registration or an exemption therefrom. The certificates for shares of the Operations Common Stock and Holdings Common Stock shall bear such legends as the issuer thereof shall deem appropriate with respect to the foregoing. 8. FURTHER ASSURANCES. (a)If at any time after the date hereof either Operations or Holdings shall consider or be advised that any deeds, bills of sale, stock powers, assignments, other documents or assurances or any other acts or things are necessary, desirable or proper to vest, perfect or confirm, of record or otherwise, any of the rights, privileges, powers, franchises, properties or assets purported to be transferred pursuant hereto, SOCO International or Story, as applicable, shall execute and deliver all such deeds, bills of sale, stock powers, assignments, other documents and assurances and do all such other acts and things necessary, desirable or proper to vest, perfect or confirm the right, title or interest of Operations or Holdings, as the case may be, in, to or under any of the rights, privileges, powers, franchises, properties or assets purported to be transferred pursuant hereto. (b) If at any time after the date hereof SOCO International shall consider or be advised that assumptions, other documents, assurances or other acts or other things are necessary, desirable or proper for Operations or Holdings, as the case may be, to effectively assume any of the obligations or liabilities purported to be assumed hereby, Operations or Holdings, as the case may be, shall execute and deliver all such assumptions, other documents and assurances and do all such other acts and things necessary, desirable or proper to effectively assume any of the obligations or liabilities purported to be assumed hereby. (c) Notwithstanding the foregoing or the terms and conditions of such additional documents, acts or things, such additional documents, acts or things shall neither increase nor decrease the scope of the assignment and assumption contemplated by this Agreement. 5 9. ASSIGNMENT. Except by operation of law or in connection with the sale of all or substantially all the assets of a party hereto, this Agreement shall not be assignable, in whole or in part, directly or indirectly, by any party hereto without the written consent of the other parties, and any attempt to assign any rights or obligations arising under this Agreement without such consent shall be void; provided, however, that the provisions of this Agreement shall be binding upon, inure to the benefit of and be enforceable by the parties hereto and their respective successors and permitted assigns. 10. PARTIES IN INTEREST. Except as herein otherwise specifically provided, nothing in this Agreement expressed or implied is intended to confer any right or benefit upon any person, firm or corporation or other entity other than the parties hereto, the SOCO International Indemnified Parties, the Operations Indemnified Parties and the Holdings Indemnified Parties, and their respective successors and permitted assigns. 11. WAIVERS, ETC. No failure or delay on the part of the parties hereto in exercising any power or right hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. No modification or waiver of any provision of this Agreement nor consent to any departure by any parties therefrom shall in any event be effective unless the same shall be in writing and signed by all such parties, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given and only against those parties who have executed such writing. 12. SEVERABILITY. If any term, provision, covenant or restriction of this Agreement is held by a court of competent jurisdiction to be invalid, void or unenforceable, the remainder of the terms, provisions, covenants and restrictions set forth herein shall remain in full force and effect and shall in no way be affected, impaired or invalidated. It is hereby stipulated and declared to be the intention of the parties that they would have executed the remaining terms, provisions, covenants and restrictions without including any thereof which may be hereafter declared invalid, void or unenforceable. In the event that any such term, provision, covenant or restriction is held to be invalid, void or unenforceable, the parties hereto shall use their reasonable efforts to find and employ an alternate means to achieve the same or substantially the same result as that contemplated by such term, provision, covenant or restriction. 13. NOTICES. Any notices to be given hereunder shall be in writing and shall be deemed to be sufficiently given when delivered personally or sent certified or registered mail, postage prepaid and return receipt requested, or by telecopy, and if intended for Story addressed to: Edward T. Story, Jr. SOCO International, Inc. 1221 Lamar Street, Suite 1200 Houston, Texas 77010 Telecopy No.: (713) 646-6676 6 or if intended for Snyder, SOCO International, Operations or Holdings, addressed to: Snyder Oil Corporation 777 Main Street, Suite 2500 Fort Worth, Texas 76012 Attention: General Counsel Telecopy No.: (817) 882-5982 Any party hereto may change the address for receiving notice upon notice to the other parties given in the manner set forth in this Section 13. 14. GOVERNING LAW. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to the principles of conflicts of law thereof. 15. AMENDMENT. This Agreement may be amended or otherwise modified only by a writing duly executed by each of the parties hereto or their respective successors or assigns. 16. HEADINGS. The section headings used in this Agreement are for convenience only and shall not be considered a part of, or affect the construction or interpretation of, any provisions of this Agreement. 17. EXECUTION OF COUNTERPARTS. This Agreement may be executed in counterparts, and each such counterpart shall be deemed to be an original instrument, but all such counterparts together for all purposes shall constitute one agreement. EXECUTED as of the day and year first written above. SNYDER OIL CORPORATION By:/s/Thomas J. Edelman ----------------------- Name: Thomas J. Edelman Title: President SOCO INTERNATIONAL, INC. By:/s/Edward T. Story, Jr. -------------------------- Name: Edward T. Story, Jr. Title: President 7 SOCO INTERNATIONAL HOLDINGS, INC. By:/s/Edward T. Story, Jr. -------------------------- Name: Edward T. Story, Jr. Title: President SOCO INTERNATIONAL OPERATIONS, INC. By:/s/Edward T. Story, Jr. -------------------------- Name: Edward T. Story, Jr. Title: President /s/Edward T. Story, Jr. ----------------------- EDWARD T. STORY, JR. 8 EX-10 3 PROMISSORY NOTE - STORY/SOCO INTERNAT'L HOLDINGS EXHIBIT 10.9.1 PROMISSORY NOTE THIS ISSUANCE OF THIS NOTE HAS NOT BEEN REGISTERED OR QUALIFIED UNDER THE SECURITIES ACT OF 1933 OR THE SECURITIES LAWS OF ANY STATE. THIS NOTE MAY NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF REGISTRATION OR QUALIFICATION UNDER SAID ACT OR ANY APPLICABLE STATE SECURITIES LAWS OR AN EXEMPTION THEREFROM. $320,936.75 December 30, 1996 - ----------- ----------------- EDWARD T. STORY, a resident of the State of Texas ("Maker"), For Value Received, promises and agrees to pay to the order of SOCO International Holdings, Inc. ("Payee"), at Snyder Oil Corporation, 777 Main Street, Suite 2500, Fort Worth, Texas, 76012, Attention: General Counsel, or at such other address as to which Payee (or any subsequent holder of this Note) shall notify Maker in writing, in lawful money of the United States of America, the principal sum of Three Hundred Twenty Thousand Nine Hundred Thirty-Six and 75/100 Dollars ($320,936.75), on or before April 10, 1998 (the "Scheduled Maturity Date"), payable together with interest on the unpaid balance thereof as provided below. 1. INTEREST. Interest shall accrue from and after the date hereof on the principal balance hereof from time to time remaining unpaid at One Percent (1%) per calendar month. Interest shall be payable on or before the Scheduled Maturity Date. 2. PREPAYMENTS. Principal and interest on this Note may be prepaid at any time without premium or penalty. 3. ACCELERATION UPON EVENTS OF DEFAULT. Payee, or any subsequent holder of this Note, may declare all unpaid amounts of principal and interest hereunder immediately due and payable by giving Maker notice of acceleration after the occurrence of an Event of Default (as hereinafter defined). An "Event of Default" shall occur (i) upon the failure by Maker to pay any amounts due under this Note as and when they become due and payable, but only if such failure continues for a period of five days after written notice thereof is dispatched by Payee to Maker, (ii) upon the filing of a petition, consent to relief or the entry of a decree or order by a court having jurisdiction in the premises for relief in respect of Maker under Title 11 of the United States Code, as now constituted or hereafter amended or (iii) upon the breach or violation by Maker of any representation, warranty, covenant or provision of that certain Formation and Capitalization Agreement by and among Snyder Oil Corporation, SOCO International, Inc., SOCO International Operations, Inc., Payee and Edward T. Story, dated as of December 30, 1996, but only if such breach or violation continues for a period of 15 days after written notice thereof is dispatched by Payee to Maker. 4. ATTORNEY'S FEES. If an Event of Default shall occur and this Note is placed in the hands of an attorney for collection, or suit is filed hereon, or bankruptcy proceedings are commenced by or against Maker, or probate, receivership or other judicial proceedings for the establishment or collection of any amount called for hereunder are commenced, or any amount payable or to be payable hereunder is collected through any such proceedings, Maker agrees to pay to the owner and holder of this Note a reasonable amount as attorney's or collection fees. 5. WAIVERS. Maker, and all persons liable or who become liable for all or any part of this Note, expressly waive demand and presentment for payment, notice of nonpayment, protest, demand, 1 notice of protest, notice of dishonor, dishonor, bringing of suit, notice of extension and diligence in taking any action to collect amounts called for hereunder and in the handling of securities at any time existing in connection herewith; and are liable for the payment of all sums owing and to be owing hereon, regardless of and without any notice, diligence, act or omission as or with respect to the collection of any amount called for hereunder or in connection with any right, lien, interest or property at any and all times had or existing as security for any amount called for hereunder. 6. NO RELEASE. The granting to Maker of an extension or extensions of time for the payment of any sum or sums due under this Note or any other agreement by the Maker with the Payee or any subsequent holder of this Note, or the exercise of or failure to exercise any right or power under this Note, or any agreement by the Maker with the Payee or any subsequent holder of this Note, shall not in any way release or affect the liability of Maker, any guarantor hereof, or any other party obligated to pay the indebtedness evidenced by this Note. 7. SEVERABILITY. If any provision of this Note or the application thereof to any party or circumstance is held invalid or unenforceable, the remainder of this Note and the application of such provision to other parties or circumstances shall not be affected thereby, the provisions of this Note being severable in any such instance. 8. SUCCESSORS. This Note shall be binding upon and shall inure to the benefit of Maker and Payee and their respective successors and assigns. 9. GOVERNING LAW. The terms of this Note shall be governed by, and interpreted in accordance with the provisions of, the laws of the State of Delaware including without limitation, all matters of construction, validity, performance and enforcement and without giving effect to the principles of conflict of laws. /s/Edward T. Story, Jr. -------------------------------- EDWARD T. STORY, JR. 2 EX-10 4 PROMISSORY NOTE - STORY/SOCO INTERNAT'L OPERATIONS EXHIBIT 10.9.2 PROMISSORY NOTE THIS ISSUANCE OF THIS NOTE HAS NOT BEEN REGISTERED OR QUALIFIED UNDER THE SECURITIES ACT OF 1933 OR THE SECURITIES LAWS OF ANY STATE. THIS NOTE MAY NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF REGISTRATION OR QUALIFICATION UNDER SAID ACT OR ANY APPLICABLE STATE SECURITIES LAWS OR AN EXEMPTION THEREFROM. $269,563.25 December 30, 1996 - ----------- ----------------- EDWARD T. STORY, a resident of the State of Texas ("Maker"), For Value Received, promises and agrees to pay to the order of SOCO International Operations, Inc. ("Payee"), at Snyder Oil Corporation, 777 Main Street, Suite 2500, Fort Worth, Texas, 76012, Attention: General Counsel, or at such other address as to which Payee (or any subsequent holder of this Note) shall notify Maker in writing, in lawful money of the United States of America, the principal sum of Two Hundred Sixty-Nine Thousand Five Hundred Sixty-Three and 25/100 Dollars ($269,563.25), on or before April 10, 1998 (the "Scheduled Maturity Date"), payable together with interest on the unpaid balance thereof as provided below. 1. Interest. Interest shall accrue from and after the date hereof on the principal balance hereof from time to time remaining unpaid at One Percent (1%) per calendar month. Interest shall be payable on or before the Scheduled Maturity Date. 2. Prepayments. Principal and interest on this Note may be prepaid at any time without premium or penalty. 3. Acceleration upon Events of Default. Payee, or any subsequent holder of this Note, may declare all unpaid amounts of principal and interest hereunder immediately due and payable by giving Maker notice of acceleration after the occurrence of an Event of Default (as hereinafter defined). An "Event of Default" shall occur (i) upon the failure by Maker to pay any amounts due under this Note as and when they become due and payable, but only if such failure continues for a period of five days after written notice thereof is dispatched by Payee to Maker, (ii) upon the filing of a petition, consent to relief or the entry of a decree or order by a court having jurisdiction in the premises for relief in respect of Maker under Title 11 of the United States Code, as now constituted or hereafter amended or (iii) upon the breach or violation by Maker of any representation, warranty, covenant or provision of that certain Formation and Capitalization Agreement by and among Snyder Oil Corporation, SOCO International, Inc., SOCO International Holdings, Inc., Payee and Edward T. Story, dated as of December 30, 1996, but only if such breach or violation continues for a period of 15 days after written notice thereof is dispatched by Payee to Maker. 4. Attorney's Fees. If an Event of Default shall occur and this Note is placed in the hands of an attorney for collection, or suit is filed hereon, or bankruptcy proceedings are commenced by or against Maker, or probate, receivership or other judicial proceedings for the establishment or collection of any amount called for hereunder are commenced, or any amount payable or to be payable hereunder is collected through any such proceedings, Maker agrees to pay to the owner and holder of this Note a reasonable amount as attorney's or collection fees. 5. Waivers. Maker, and all persons liable or who become liable for all or any part of this Note, expressly waive demand and presentment for payment, notice of nonpayment, protest, demand, 1 notice of protest, notice of dishonor, dishonor, bringing of suit, notice of extension and diligence in taking any action to collect amounts called for hereunder and in the handling of securities at any time existing in connection herewith; and are liable for the payment of all sums owing and to be owing hereon, regardless of and without any notice, diligence, act or omission as or with respect to the collection of any amount called for hereunder or in connection with any right, lien, interest or property at any and all times had or existing as security for any amount called for hereunder. 6. No Release. The granting to Maker of an extension or extensions of time for the payment of any sum or sums due under this Note or any other agreement by the Maker with the Payee or any subsequent holder of this Note, or the exercise of or failure to exercise any right or power under this Note, or any agreement by the Maker with the Payee or any subsequent holder of this Note, shall not in any way release or affect the liability of Maker, any guarantor hereof, or any other party obligated to pay the indebtedness evidenced by this Note. 7. Severability. If any provision of this Note or the application thereof to any party or circumstance is held invalid or unenforceable, the remainder of this Note and the application of such provision to other parties or circumstances shall not be affected thereby, the provisions of this Note being severable in any such instance. 8. Successors. This Note shall be binding upon and shall inure to the benefit of Maker and Payee and their respective successors and assigns. 9. Governing Law. The terms of this Note shall be governed by, and interpreted in accordance with the provisions of, the laws of the State of Delaware including without limitation, all matters of construction, validity, performance and enforcement and without giving effect to the principles of conflict of laws. /s/Edward T. Story --------------------------------- EDWARD T. STORY, JR. 2 EX-10 5 FIFTH AMENDMENT TO FIFTH RESTATED CREDIT AGREEMENT EXHIBIT 10.11.5 FIFTH AMENDMENT TO FIFTH RESTATED CREDIT AGREEMENT This Fifth Amendment to Fifth Restated Credit Agreement (this "FIFTH AMENDMENT") is entered into as of the 1st day of November, 1996, by and among Snyder Oil Corporation ("BORROWER"), NationsBank of Texas, N.A., as Agent ("AGENT"), and NationsBank of Texas, N.A. ("NATIONSBANK"), Bank One, Texas, N.A. ("BANK ONE"), Wells Fargo Bank, N.A. ("WELLS FARGO"), and Texas Commerce Bank National Association ("TCB") as Banks (the "BANKS"). W I T N E S E T H: WHEREAS, the Banks, Borrower and Agent are parties to that certain Fifth Restated Credit Agreement dated as of June 30, 1994, as amended by that certain (i) letter agreement by and among Borrower and the Banks dated as of May 1, 1995, (ii) Second Amendment to Fifth Restated Credit Agreement by and among Borrower, Agent and the Banks dated as of June 30, 1995, (iii) Third Amendment to Fifth Restated Credit Agreement by and among Borrower, Agent and the Banks dated as of November 1, 1995, and (iv) Fourth Amendment to Fifth Restated Credit Agreement by and among Borrower, Agent and the Banks dated as of April 4, 1996 (as amended, the "CREDIT AGREEMENT") (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement); and WHEREAS, pursuant to the Credit Agreement the Banks have made certain Loans to Borrower, and Agent has issued certain Letters of Credit on behalf of Borrower; and WHEREAS, Borrower has requested that (i) the Banks waive their right to make a Special Determination of the Borrowing Base in connection with any sale or sales of the Sale Properties (as herein defined), (ii) Section 9.2 of the Credit Agreement be amended in certain respects, (iii) Section 9.11 of the Credit Agreement be amended in certain respects, (iv) the amount of the Total Borrowing Base and the amounts of the Facility A Borrowing Base and the Facility B Borrowing Base for the period commencing on November 1, 1996 and continuing until the next succeeding Determination Date be set forth herein, and (v) the Banks extend the Facility B Termination Date to October 30, 1997; and WHEREAS, subject to the terms and conditions herein contained, the Banks have agreed to Borrower's requests. NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Agent and each Bank hereby agree as follows: SECTION 1. AMENDMENTS. Subject to the satisfaction of each condition precedent set forth in SECTION 5 hereof and in reliance on the representations, warranties, covenants and agreements contained in this Fifth Amendment, the Credit Agreement shall be amended effective November 1, 1996 (the "EFFECTIVE DATE") in the manner provided in this SECTION 1. 1 1.1. AMENDMENT TO DEFINITIONS. The definition of "Loan Papers" contained in Section 1.1 of the Credit Agreement shall be amended to read in full as follows: "Loan Papers" means this Agreement, the Letter Agreement, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Notes, the Mortgages, the Restricted Subsidiary Guarantees and all other certificates, documents or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time. 1.2. ADDITIONAL DEFINITIONS. Section 1.1 of the Credit Agreement shall be amended to add the following definition to such Section: "Fifth Amendment" means that certain Fifth Amendment to Fifth Restated Credit Agreement dated as of November 1, 1996, by and among Borrower, Agent and the Banks. 1.3. RESTRICTED PAYMENTS COVENANT. Section 9.2 of the Credit Agreement shall be amended to read in full as follows: SECTION 9.2. RESTRICTED PAYMENTS. Neither Borrower nor any Restricted Subsidiary will declare or make any Restricted Payment; provided, that, so long as no Default or Event of Default, Borrowing Base Deficiency or noncompliance with SECTION 10.4 exists (without giving effect to the cure periods provided by SECTION 4.4 or 10.4), and provided further that no Default or Event of Default, Borrowing Base Deficiency or non compliance with SECTION 10.4 would result from such Restricted Payment (without giving effect to the cure periods provided by SECTION 4.4 or 10.4), Borrower and Restricted Subsidiaries may (a) make Restricted Payments in an aggregate amount (measured cumulatively from January 1, 1996) not to exceed the sum of the following (i) $75,000,000, plus (ii) the net cash proceeds to Borrower from all equity offerings completed by Borrower of Borrower's equity securities after January 1, 1996, plus (iii) all cash Distributions actually received by Borrower or any Restricted Subsidiary from Unrestricted Subsidiaries after January 1, 1996, plus (iv) fifty percent (50%) of Borrower's Consolidated Cash Flow earned on or after January 1, 1996 to the earlier of (y) the date of determination, or (z) December 31, 1996, (b) declare and make a Qualified Redemption of the First Issue, (c) declare and make a Qualified Redemption of the Second Issue, (d) declare and make a Qualified Redemption of the Third Convertible Debentures, (e) issue the First Convertible Debentures in exchange for the First Preferred Stock, and (f) issue the Second Convertible Debentures in exchange for the Second Preferred Stock. Notwithstanding the foregoing, the aggregate amount of Distributions consisting of dividends paid on or with respect to the Common Stock of Borrower shall not exceed $.30 per weighted average share outstanding during any period of four (4) consecutive fiscal quarters. Furthermore, provided, that, no Default or Event of Default, Borrowing Base Deficiency or noncompliance with SECTION 10.4 has occurred which is continuing (without giving effect to the cure periods provided by SECTION 4.4 or 10.4), on May 1, 1997, (Y) subsection (a)(iv) of this SECTION 9.2 shall be automatically amended, 2 without the necessity of any further action by Borrower, Agent or any Bank, to read in full as follows: "(iv) fifty percent (50%) of Borrower's Consolidated Cash Flow earned on or after January 1, 1996 to the date of determination," and, (Z) the sentence immediately preceding this sentence and beginning with the phrase "Notwithstanding the foregoing" shall automatically be deleted in its entirety without the necessity of any further action by Borrower, Agent or any Bank. 1.4. HEDGE TRANSACTIONS COVENANT. Section 9.11 of the Credit Agreement shall be amended to read in full as follows: SECTION 9.11. HEDGE TRANSACTIONS. Neither Borrower nor any of its Restricted Subsidiaries shall enter into Hedge Transactions with the exception that Borrower and its Restricted Subsidiaries may enter into Hedge Transactions as long as (a) (i) the aggregate notional volume of oil which is the subject of oil Hedge Transactions in existence at any time does not exceed seventy-five percent (75%) of Borrower's and its Restricted Subsidiaries' anticipated production of oil from proved, developed producing reserves during the entire term of such existing Hedge Transactions, and (ii) the notional volume of oil with respect to which a settlement is required on a particular settlement date under such oil Hedge Transactions shall not exceed (A) ninety percent (90%) of Borrower's and its Restricted Subsidiaries anticipated production of oil from proved, developed producing reserves for the period (a "Settlement Period") from the immediately preceding settlement date under any oil Hedge Transaction (or the commencement of such Hedge Transaction in the event there is no prior settlement date) to such settlement date in the case of any Settlement Period ending on or prior to April 30, 1997, and (B) seventy five percent (75%) of Borrower's and its Restricted Subsidiaries' anticipated production of oil from proved, developed producing reserves for any Settlement Period thereafter, and (b) (i) the aggregate notional volume of gas which is the subject of gas Hedge Transactions in existence at any time does not exceed seventy-five percent (75%) of Borrower's and its Restricted Subsidiaries' anticipated production of gas from proved, developed producing reserves during the entire term of such existing Hedge Transactions, and (ii) the notional volume of gas with respect to which a settlement is required on a particular settlement date under such gas Hedge Transactions shall not exceed (A) ninety percent (90%) of Borrower's and its Restricted Subsidiaries' anticipated production of gas from proved, developed producing reserves for the Settlement Period ending on such settlement date in the case of any Settlement Period ending on or prior to April 30, 1997, and (B) seventy five percent (75%) of Borrower's and its Restricted Subsidiaries' anticipated production of gas from proved, developed producing reserves for any Settlement Period thereafter. SECTION 2. SALE OF SALE PROPERTIES. Borrower has advised the Banks that Borrower intends to sell the Borrower's interest in some or all of the oil and gas properties described on EXHIBIT I attached hereto (the "SALE PROPERTIES"). Borrower has further advised the Banks that it intends to complete any such sale or sales of the Sale Properties pursuant to the exception to Section 9.5 of the Credit Agreement contained in clause (z) of such Section, and Borrower has requested that the Banks waive their right to make a Special Determination of the Borrowing Base in connection with any such specific sale. The Banks hereby (i) agree with Borrower that any sale or sales of the Sale 3 Properties (the "APPROVED SALES") will be deemed sales under clause (z) of Section 9.5 of the Credit Agreement and will not reduce or eliminate exceptions to Section 9.5 of the Credit Agreement available under any other clause of Section 9.5, and (ii) waive their right to require a Special Determination of the Borrowing Base in connection with any such Approved Sales. The waiver granted by the Banks in this SECTION 2 is expressly limited as follows: (a) such waiver is limited solely to Section 9.5 of the Credit Agreement and solely with respect to the Approved Sales, (b) such waiver shall not be applicable to any provision of any Loan Paper other than Section 9.5 of the Credit Agreement, and (c) such waiver is a limited, one-time waiver, and nothing contained herein shall obligate the Banks to grant any additional, or future waiver of Section 9.5 of the Credit Agreement or any other provision of any Loan Paper. SECTION 3. BORROWING BASE. In accordance with Section 4.1 and 4.4 of the Credit Agreement, effective November 1, 1996, and continuing until the next Determination Date, the Total Borrowing Base shall be $140,000,000, allocated as follows: $90,000,000 to the Facility A Borrowing Base, and $50,000,000 to the Facility B Borrowing Base. SECTION 4. EXTENSION OF FACILITY B TERMINATION DATE. In accordance with Section 2.9(b) of the Credit Agreement, Borrower has requested that the Banks extend the Facility B Termination Date from April 3, 1997 to October 30, 1997. The Facility B Termination Date is hereby extended from April 3, 1997 to October 30, 1997. SECTION 5. CONDITIONS PRECEDENT TO EFFECTIVENESS OF AMENDMENTS. The amendments to the Credit Agreement contained in SECTION 1 of this Fifth Amendment shall be effective only upon, and are conditioned upon, the delivery to Agent of such resolutions, certificates and other documents as Agent shall request relative to the authorization, execution and delivery by Borrower of this Fifth Amendment. If the foregoing condition has not been satisfied by the Effective Date, this Fifth Amendment and all obligations of the Banks and Agent contained herein shall, at the option of Majority Banks, terminate. SECTION 6. REPRESENTATIONS AND WARRANTIES OF BORROWER. To induce the Banks and Agent to enter into this Fifth Amendment, Borrower hereby represents and warrants to Agent as follows: (a) Each representation and warranty of Borrower contained in the Credit Agreement and the other Loan Papers is true and correct on the date hereof and will be true and correct after giving effect to the amendments set forth in SECTION 1 hereof. (b) The execution, delivery and performance by Borrower of this Fifth Amendment are within the Borrower's corporate powers, have been duly authorized by necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any Material Agreement binding upon Borrower or the Subsidiaries of Borrower or result in the creation or imposition of any Lien upon any of the assets of Borrower or the Subsidiaries of Borrower except Permitted Encumbrances. 4 (c) This Fifth Amendment constitutes the valid and binding obligation of Borrower enforceable in accordance with its terms, except as (i) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor's rights generally, and (ii) the availability of equitable remedies may be limited by equitable principles of general application. SECTION 7. MISCELLANEOUS. 7.1 NO DEFENSES. Borrower hereby represents and warrants to the Banks that there are no defenses to payment, counterclaims or rights of set-off with respect to the Loans existing on the date hereof. 7.2 REAFFIRMATION OF LOAN PAPERS; EXTENSION OF LIENS. Any and all of the terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect. Borrower hereby extends the Liens securing the Obligations until the Obligations have been paid in full, and agrees that the amendments and modifications herein contained shall in no manner affect or impair the Obligations or the Liens securing payment and performance thereof. 7.3 PARTIES IN INTEREST. All of the terms and provisions of this Fifth Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns. 7.4 LEGAL EXPENSES. Borrower hereby agrees to pay on demand all reasonable fees and expenses of counsel to Agent incurred by Agent, in connection with the preparation, negotiation and execution of this Fifth Amendment and all related documents. 7.5 COUNTERPARTS. This Fifth Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Fifth Amendment until all parties have executed a counterpart. Facsimiles shall be effective as originals. 7.6 COMPLETE AGREEMENT. THIS FIFTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. 7.7 HEADINGS. The headings, captions and arrangements used in this Fifth Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Fifth Amendment, nor affect the meaning thereof. 5 IN WITNESS WHEREOF, the parties hereto have caused this Fifth Amendment to be duly executed by their respective authorized officers on the date and year first above written. BORROWER: SNYDER OIL CORPORATION, a Delaware corporation By:/s/Peter E. Lorenzen ----------------------- Its:Vice President AGENT: NATIONSBANK OF TEXAS, N.A. By:/s/Scott Fowler ------------------ Its:Vice President BANKS: NATIONSBANK OF TEXAS, N.A. By:/s/Scott Fowler ------------------ Its:Vice President TEXAS COMMERCE BANK NATIONAL ASSOCIATION By:/s/Tim Perry ------------------------- Its:Senior Vice President BANK ONE, TEXAS, N.A. By:/s/Brad Bartek ----------------- Its:Vice President WELLS FARGO BANK, N.A. By:/s/Chad Kirkham ------------------ Its:Vice President 6 EX-11 6 COMPUTATION OF NET INCOME (LOSS) PER COMMON SHARE EXHIBIT 11.1 SNYDER OIL CORPORATION Computation of Net Income (Loss) per Common Share For The Years Ended December 31, 1994, 1995 and 1996 (In thousands except per share data)
Year Ended December 31, --------------------------------------------------- 1994 1995 1996 ------------- ------------- -------------- Net income (loss) $12,372 ($39,831) $62,950 Dividends on preferred stock (10,806) (6,210) (6,210) ------------- ------------- -------------- Net income (loss) available to common $1,566 ($46,041) $56,740 ============= ============= ============== Weighted average shares outstanding 23,704 30,186 31,308 Assumed exercise of vested common stock options net of treasury shares repurchased 290(a) 138(c) 179(d) Assumed conversion of 6% preferred stock 4,881(b) 4,881(b) 5,051(e) ------------- ------------- -------------- Weighted average common stock and equivalents outstanding 28,875 35,205 36,538 ============= ============= ============== PRIMARY NET INCOME (LOSS) PER COMMON SHARE: Net income (loss) $0.52 ($1.32) $2.01 Dividends on preferred stock (0.45) (0.21) (0.20) ------------- ------------- -------------- Net income (loss) available to common $0.07 ($1.53) $1.81 ============= ============= ============== FULLY DILUTED NET INCOME (LOSS) PER COMMON SHARE: Net income (loss) $0.43 ($1.13) $1.72 Dividends on preferred stock 0.00 0.00 0.00 ------------- ------------- -------------- Net income (loss) available to common $0.43 ($1.13) $1.72 ============= ============= ============== Antidilutive Antidilutive Dilutive (a) Computed as 532,837 shares assumed to be issued upon exercise of vested options less 242,690 shares assumed to be purchased and held in treasury ($4,421,814 proceeds divided by $18.22 average closing price). (b) 4,100,000 shares X $25.00/$21.00. Should be 4,140,000 shares, but will leave the same as reported in prior years. (c) Computed as 743,285 shares assumed to be issued upon exercise of vested options less 605,327 shares assumed to be purchased and held in treasury ($7,802,659 proceeds divided by $12.89 average closing price). (d) Computed as 772,155 shares assumed to be issued upon exercise of vested options less 593,111 shares assumed to be purchased and held in treasury ($10,308,269 proceeds divided by $17.38 ending market price). (e) 4,134,000 shares X $25.00/$20.46.
EX-12 7 COMPUTATION OF RATIOS EXHIBIT 12 SNYDER OIL CORPORATION COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (UNAUDITED)
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------ 1992 1993 1994 1995 1996 ----------- ----------- ----------- ----------- ----------- (DOLLARS IN THOUSANDS) Income (loss) before taxes, minority interest and extraordinary item $15,027 $22,538 $13,510 ($40,604) $75,701 Interest expense 4,997 5,315 10,337 21,679 23,587 ----------- ----------- ----------- ----------- ----------- Earnings before taxes, minority interest, extraordinary item and fixed charges 20,024 27,853 23,847 (18,925) 99,288 =========== =========== =========== =========== =========== Fixed Charges: Interest expense 4,997 5,315 10,337 21,679 23,587 Preferred stock dividends of majority owned subsidiary - - - - 1,520 ----------- ----------- ---------- ----------- ----------- Total fixed charges $4,997 $5,315 $10,337 $21,679 $25,107 =========== =========== =========== =========== =========== Ratio of earnings to fixed charges 4.01 5.24 2.31 (0.87) 3.95 =========== =========== =========== =========== ===========
1 SNYDER OIL CORPORATION COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS (UNAUDITED)
YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 1992 1993 1994 1995 1996 ----------- ----------- ----------- ----------- ----------- (DOLLARS IN THOUSANDS) Income (loss) before taxes, minority interest and extraordinary item $15,027 $22,538 $13,510 ($40,604) $75,701 Interest expense 4,997 5,315 10,337 21,679 23,587 ----------- ----------- ----------- ----------- ----------- Earnings before taxes, minority interest, extraordinary item and fixed charges 20,024 27,853 23,847 (18,925) 99,288 =========== =========== =========== =========== =========== Fixed Charges: Interest expense 4,997 5,315 10,337 21,679 23,587 Preferred stock dividends 4,800 9,100 10,806 6,210 6,210 Preferred stock dividends majority owned subsidiary - - - - 1,520 ----------- ----------- ----------- ----------- ----------- Total fixed charges $9,797 $14,415 $21,143 $27,889 $31,317 =========== =========== =========== =========== =========== Ratio of earnings to combined fixed charges and preferred dividends 2.04 1.93 1.13 (0.68) 3.17 ============ ========== =========== =========== ========== 2
EX-22 8 SUBSIDIARIES OF THE REGISTRANT EXHIBIT 22.1 SNYDER OIL CORPORATION SUBSIDIARIES AS OF MARCH 10, 1997 State of Name of Subsidiary Organization ------------------ ------------- Patina Oil & Gas Corporation Delaware SOCO Wattenberg Corporation Delaware Gerrity Oil & Gas Corporation Delaware SOCO International, Inc. Delaware The names of other subsidiaries are omitted in accordance with Item 601(b)(22)(ii) of Regulation S-K. EX-23 9 CONSENT OF ARTHUR ANDERSEN EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 17, 1997 on the financial statements of Snyder Oil Corporation included in this Form 10-K, into Snyder Oil Corporation's previously filed Registration Statement File Nos. 33-34446, 33-45213, 33- 54809, 33-64219 and 333-09877. ARTHUR ANDERSEN LLP Fort Worth, Texas, March 10, 1997 EX-23 10 CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. EXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND CONSULTANTS As independent petroleum consultants, we hereby consent to the incorporation of our reports included in this Form 10-K into Snyder Oil Corporation's Registration Statement Nos. 33-34446, 33-45213, 33- 54809, 33-64219 and 333-09877. NETHERLAND, SEWELL & ASSOCIATES, INC. By:/s/ Frederic D. Sewell ----------------------------------- Frederic D. Sewell President Dallas, Texas March 11, 1997 EX-23 11 CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINEERS EXHIBIT 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND CONSULTANTS As independent petroleum consultants, we hereby consent to the incorporation of the references to us in this Form 10-K into Snyder Oil Corporation's Registration Statement Nos. 33-34446, 33-45213, 33- 54809, 33-64219 and 333-09877. RYDER SCOTT COMPANY PETROLEUM ENGINEERS Houston, Texas March 10, 1997 EX-27 12 FDS WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
5 1,000 US $ Year Dec-31-1996 Jan-01-1996 Dec-31-1996 27,922 0 58,944 0 3,403 98,078 910,700 261,502 879,459 88,910 372,073 0 10 315 294,343 879,459 206,982 292,414 136,601 154,081 19,713 0 24,179 74,701 4,346 62,950 0 0 0 62,950 1.81 1.72
EX-99 13 RESERVE LETTER NSAI TO SOCO EXHIBIT 99.1 February 4, 1997 Snyder Oil Corporation Suite 2500 777 Main Street Forth Worth, Texas 76102 Gentlemen: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 1996, to the Snyder Oil Corporation (SOCO) interest in certain oil and gas properties located in the United States and in federal waters offshore Louisiana as listed in the accompanying tabulations. As requested, lease and well operating costs do not include the per-well overhead expenses allowed under joint operating agreements for those properties operated by SOCO. This report has been prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the SOCO interest, as of December 31, 1996, to be: Net Reserves Future Net Revenue
Net Reserves Future Net Revenue ------------------------------------- --------------------------------------- Oil Gas Present Worth Category (Barrels) (MCF) Total at 10% - --------------------------- --------------- ---------------- ----------------- ------------------ Proved Developed Producing 13,159,701 145,971,065 $ 517,276,200 $ 287,013,000 Non-Producing 603,626 2,096,499 13,474,300 7,602,100 Proved Undeveloped 1,935,000 105,239,714 291,643,300 134,424,700 --------------- ---------------- ----------------- ---------------- Total Proved 15,698,327 253,307,278 $ 822,393,800 $ 429,039,800
The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (MCF) at the contract temperature and pressure bases. As shown in the Table of Contents, the properties in this report have been subdivided into project areas behind the appropriate division tab. Included for each project area are summary projections of reserves and revenue for each reserve category along with one-line summaries of reserves, economics, and basic data by lease for each significant property group. For the purposes of this report, the term "lease" refers to a single economic projection. The estimated reserves and future revenue shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimate do not include any value for probable or possible reserves which may exit for these properties. This report does not include any value which could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated Future gross revenue to the SOCO interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deducting these taxes, future capital costs, and operating expenses, but before consideration of federal income taxes; future net revenue for the offshore properties is also after deducting abandonment costs. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its "present worth." The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties. For the purposes of this report, a field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs which may be incurred due to such possible liability. Our estimates of future revenue do not include any salvage value for the lease and well equipment nor the cost of abandoning the onshore properties. Future revenue estimates for offshore properties also do not include any salvage value for the lease and well equipment, but do include our estimates of the costs to abandon the wells, platforms, and production facilities. Abandonment costs for offshore properties are included with other capital investments. Oil prices used in this report are based on a December 31, 1996 West Texas Intermediate posted price of $24.25 per barrel, adjusted by significant property group for regional posted price differentials. Gas prices used in this report are based on average December 1996 prices by pipeline for each significant property group. Oil and gas prices are held constant in accordance with SEC guidelines. Lease and well operating costs are based on operating expense records of SOCO. For non-operated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease and field level costs. Headquarters general and administrative overhead expenses of SOCO are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment. We have made no investigation of potential gas volume and value imbalances which may have resulted from overdelivery or underdelivery to the SOCO interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on SOCO receiving its net revenue interest share of estimated future gross gas production. The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. The sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in this report due to governmental policies and uncertainties of supply and demand. Also, estimates of reserves may increase or decrease as a result of future operations. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering and geological, interpretation may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions necessarily represent only informed professional judgments. The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Snyder Oil Corporation and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are independent petroleum engineers, geologists, and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together with our engineering work sheets are maintained on file in our office. Very truly yours, /s/ Clarence Netherland Netherland Sewell & Associates, Inc. RKG:AKC EX-99 14 RESERVE LETTER NSAI TO PATINA EXHIBIT 99.2 February 5, 1997 Patina Oil & Gas Corporation Suite 2000 1625 Broadway Denver, Colorado 80202 Gentlemen: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 1996, to the Patina Oil & Gas Corporation (Patina) interest in certain oil and gas properties located in Colorado. As requested, lease and well operating costs do not include the per-well overhead expenses allowed under joint operating agreements for those properties operated by Patina. This report has been prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the Patina interest, as of December 31, 1996, to be:
Net Reserves Future Net Revenue ------------------------------------ ---------------------------------------- Oil Gas Present Worth Category (Barrels) (MCF) Total at 10% - --------------------------- --------------- ---------------- ----------------- ------------------ Proved Developed Producing 12,971,418 206,872,544 $ 824,044,600 $ 500,440,700 Non-Producing 2,827,690 35,904,440 156,219,400 81,966,600 Proved Undeveloped 6,676,152 53,882,147 188,602,900 66,389,200 --------------- ---------------- ----------------- ------------------ Total Proved 22,475,260 296,659,131 $1,168,866,900 $ 648,796,500
The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (MCF) at the contract temperature and pressure bases. As shown in the Table of Contents, this report includes summary projections of reserves and revenue for each reserve category along with one-line summaries of reserves, economics, and basic data by lease. For the purposes of this report, the term "lease" refers to a single economic projection. The estimated reserves and future revenue shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any value for probable or possible reserves which may exist for these properties. This report does not include any value which could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Future gross revenue to the Patina interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deducting these taxes, future capital costs, and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its "present worth." The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties. For the purposes of this report, a field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs which may be incurred due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment nor the cost of abandoning the properties. Oil prices used in this report are based on a December 31, 1996 West Texas Intermediate posted price of $24.25 per barrel, adjusted by lease for gravity, transportation fees, and regional posted price differentials. Gas prices used in this report are the average December 1996 prices for each pipeline. Oil and gas prices are held constant in accordance with SEC guidelines. Lease and well operating costs are based on operating expense records of Patina. For non-operated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease and field level costs. Headquarters general and administrative overhead expenses of Patina are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment. We have made no investigation of potential gas volume and value imbalances which may have resulted from overdelivery or underdelivery to the Patina interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Patina receiving its net revenue interest share of estimated future gross gas production. The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. The sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in this report due to governmental policies and uncertainties of supply and demand. Also, estimates of reserves may increase or decrease as a result of future operations. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering and geological, interpretation may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions necessarily represent only informed professional judgments. The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Patina Oil & Gas Corporation and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are independent petroleum engineers, geologists, and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together with our engineering work sheets are maintained on file in our office. Very truly yours, /S/ CLARENCE NETHERLAND ------------------------------- Netherland Sewell & Associates, Inc. RKG:HAY EX-99 15 RESERVE LETTER FROM RYDER SCOTT FOR SOCO OFFSHORE EXHIBIT 99.3 February 5, 1997 SOCO Offshore, Inc. A subsidiary of Snyder Oil Corporation 1221 Lamar, Suite 1200 Houston, Texas 77010 Gentlemen: At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of SOCO Offshore, Inc. (SOCO) as of December 31, 1996. The subject properties are located in the state of Texas and in the federal waters offshore Louisiana and Texas. The income data were estimated using the Securities and Exchange Commission (SEC) guidelines for future price and cost parameters. The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. December 1996 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from December 1996 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below. SEC PARAMETERS Estimated Net Reserves and Income Data Certain Leasehold and Royalty Interests of SOCO OFFSHORE, INC. As of December 31, 1996 ----------------------------------------------------------------------------------------
PROVED --------------------------------------------------------------------------------------- DEVELOPED TOTAL --------------------------------------------- PRODUCING NON-PRODUCING UNDEVELOPED PROVED ------------------ --------------------- ------------------ ------------------- NET REMAINING RESERVES OIL/CONDENSATE - BARRELS 1,130,123 614,980 35,461 1,780,564 GAS - MMCF 38,952 14,712 1,170 54,834 INCOME DATA FUTURE GROSS REVENUE $182,774,740 $74,060,517 $5,589,874 $262,452,131 DEDUCTIONS 30,263,094 16,604,502 4,099,373 50,966,969 -------------- ------------ ----------- -------------- FUTURE NET INCOME (FNI) $152,511,646 $57,456,015 $1,490,501 $211,458,162 DISCOUNTED FNI @ 10% $139,086,667 $35,973,701 $ 523,445 $175,583,813
PROBABLE -------------------------------------------------------------------------------------------- DEVELOPED TOTAL ------------------------------------------- PRODUCING NON-PRODUCING UNDEVELOPED PROBABLE ----------------- -------------------- ------------------ ----------------- NET REMAINING RESERVES OIL/CONDENSATE - BARRELS 274,627 40,422 37,763 352,812 GAS - MMCF 5,943 3,903 1,246 11,092 INCOME DATA FUTURE GROSS REVENUE $30,479,322 $16,291,982 $5,952,614 $52,723,918 DEDUCTIONS 148,298 752,249 3,248 903,795 -------------- -------------- -------------- -------------- FUTURE NET INCOME (FNI) $30,331,024 $15,539,733 $5,949,366 $51,820,123 DISCOUNTED FNI @ 10% $21,772,784 $ 8,181,240 $5,064,732 $35,018,756
POSSIBLE ---------------------------------------------------------------------------------------------- DEVELOPED TOTAL --------------------------------------------- PRODUCING NON-PRODUCING UNDEVELOPED POSSIBLE ------------------ --------------------- ------------------- ----------------- NET REMAINING RESERVES OIL/CONDENSATE - BARRELS 239,006 94 37,568 276,668 GAS - MMCF 2,915 1,122 1,240 5,277 INCOME DATA FUTURE GROSS REVENUE $17,440,154 $4,316,005 $5,921,988 $27,678,147 DEDUCTIONS 128,986 128,251 2,050 259,287 -------------- ------------ -------------- -------------- FUTURE NET INCOME (FNI) $17,311,168 $4,187,754 $5,919,938 $27,418,860 DISCOUNTED FNI @ 10% $10,805,217 $2,092,899 $4,990,695 $17,888,811
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. at SOCO's request, gas imbalances for four fields were included in this report. The fields were Eugene Island 342, East Cameron 317/318, Eugene Island 324, and Eugene Island 198/199/202. Gas reserves account for approximately 83 percent and Liquid hydrocarbon reserves account for the remaining 17 percent of total future gross revenue from proved reserves. The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below.
DISCOUNTED FUTURE NET INCOME AS OF DECEMBER 31, 1996 --------------------------------------------------------------------- DISCOUNT RATE TOTAL TOTAL TOTAL PERCENT PROVED PROBABLE POSSIBLE ---------------------- --------------------- -------------------- ------------------ 5 $192,063,468 $42,306,871 $21,991,600 15 $161,504,807 $29,357,298 $14,751,966 20 $149,392,052 $24,900,590 $12,326,477 25 $138,890,657 $21,347,634 $10,429,946
The results shown above are presented for your information and should not be construed as our estimate of fair market value. RESERVES INCLUDED IN THIS REPORT The PROVED RESERVES included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The PROBABLE RESERVES and POSSIBLE RESERVES included herein conform to definitions of probable and possible reserves approved by the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. The definitions of proved, probable, and possible reserves are included under the tab "Reserve Definitions and Pricing Assumptions" in this report. We have included probable and possible reserves and income in this report at the request of SOCO. These data are for SOCO's information only and should not be included in reports to the SEC according to the SEC guidelines. The probable reserves are less certain to be recovered than the proved reserves and reserves classified as possible are less certain to be recovered than those in the probable category. The reserves and income quantities attributable to the different reserve classifications that are included herein have not been adjusted to reflect the varying degrees of risk associated with them and thus are not comparable. The proved developed non-producing reserves included herein are comprised of shut-in and behind pipe categories. The probable developed non-producing reserves included herein are comprised of the behind pipe category. The possible developed non-producing reserves included herein are comprised of the behind pipe category. The various reserve status categories are defined under the tab "Reserve Definitions and Pricing Assumptions" in this report. ESTIMATES OF RESERVES Producing reserves included herein were estimated by the performance method and the volumetric method. The performance method utilized extrapolations of various historical data. Non- producing and undeveloped reserves included herein were estimated by the volumetric method. All of the reserves included herein were based only on primary recovery The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. FUTURE PRODUCTION RATES Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by SOCO. We estimated that future gas production rates limited by allowables or marketing conditions will continue to be the same as the average rate for the latest available 12 months of actual production until such time that the well or wells are incapable of producing at this rate. The well or wells were then projected to decline at their decreasing delivery capacity rate. The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. HYDROCARBON PRICES SOCO furnished us with prices in effect at December 31, 1996 and these prices were held constant. In accordance with Securities and Exchange Commission guidelines, changes in liquid and gas prices subsequent to December 31, 1996 were not taken into account in this report. Future prices used in this report are discussed in more detail under the tab "Reserve Definitions and Pricing Assumptions" in this report. COSTS Operating costs for leases and wells in this report were provided by SOCO. They were accepted without independent verification. SOCO informs us that these costs are representative of the historical costs directly applicable to the leases or wells. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells. Development costs were furnished to us by SOCO and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for all of the properties. The estimates of the net abandonment costs furnished by SOCO were accepted without independent verification. Current costs were held constant throughout the life of the properties. GENERAL Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 212 present our estimated projection of production and income by years beginning January 1, 1997, by program, field, and lease or well. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. The estimates of reserves presented herein were based upon a detailed study of the properties in which SOCO owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. SOCO has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by SOCO were accepted without independent verification. The estimates presented in this report are based on data available through December 1996. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties. This report was prepared for the exclusive use and sole benefit of SOCO Offshore, Inc. The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY PETROLEUM ENGINEERS Joseph E. Blankenship, P.E. Senior Petroleum Engineer JEB/sw Approved: - ------------------------------------- Joseph E. Magoto, P.E. Group Vice President -----END PRIVACY-ENHANCED MESSAGE-----