SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [ x ] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 1996. [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Commission File Number 0-20872 ST. MARY LAND & EXPLORATION COMPANY (Exact name of Registrant as specified in its charter) Delaware 41-0518430 (State or other Jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1776 Lincoln Street, Suite 1100, Denver, Colorado 80203 (Address of principal executive offices) (Zip Code) (303) 861-8140 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b)of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.01 par value (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 filer pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ x ] The aggregate market value of 9,560,325 shares of voting stock held by non-affiliates of the Registrant, based upon the closing sale price of the Common Stock on March 21, 1997 of $25.125 per share as reported on the Nasdaq National Market System, was $240,203,166. Shares of Common Stock held by each officer and director and by each person who owns 5% or more of the outstanding Common Stock and who may be deemed an affiliate have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. As of March 21, 1997, the Registrant had 10,942,759 shares of Common Stock outstanding. DOCUMENT INCORPORATED BY REFERENCE The information required by Part III (Items 10, 11, 12 and 13) is incorporated by reference from Registrant's definitive Proxy Statement relating to its 1997 Annual Meeting of Stockholders. TABLE OF CONTENTS ITEM PAGE PART I ITEM 1. BUSINESS...................................................... 4 Background............................................... 4 Business Strategy........................................ 4 Significant Developments Since December 31, 1995......... 5 ITEM 2. PROPERTIES.................................................... 6 Domestic Operations...................................... 6 International Operations.................................12 Key Relationships........................................13 Acquisitions.............................................13 Reserves.................................................13 Production...............................................14 Productive Wells.........................................15 Drilling Activity........................................15 Domestic and International Acreage.......................16 Non-Oil and Gas Activities...............................16 Competition..............................................17 Markets and Major Customers..............................17 Government Regulations...................................17 Title to Properties......................................18 Operational Hazards and Insurance........................18 Employees and Office Space...............................19 Glossary.................................................19 ITEM 3. LEGAL PROCEEDINGS.............................................21 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........21 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDERS MATTERS.............................22 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA..........................23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...........................25 Overview.................................................25 Results of Operations....................................27 Liquidity and Capital Resources..........................29 Accounting Matters.......................................32 Effects of Inflation and Changing Prices.................33 TABLE OF CONTENTS (Continued) ITEM PAGE ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..................34 ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..........................34 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...........34 ITEM 11. EXECUTIVE COMPENSATION.......................................34 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...............................................34 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...............34 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K..........................................35 ITEM 1. BUSINESS Background St. Mary Land & Exploration Company ("St. Mary" or the "Company") is an independent energy company engaged in the exploration, development, acquisition and production of crude oil and natural gas. St. Mary's operations are focused in five core operating areas in the United States: the Mid-Continent region; the ArkLaTex region; south Louisiana; the Williston Basin; and the Permian Basin. As of December 31, 1996, the Company had estimated net proved reserves of approximately 10.7 MMBbls of oil and 127.1 Bcf of natural gas, or an aggregate of 31.9 MMBOE (84% proved developed, 66% gas) with a PV-10 Value of $296.5 million. From January 1, 1994 through December 31, 1996, the Company added estimated net proved reserves of 28.5 MMBOE at an average finding cost of approximately $4.05 per BOE. Average daily production increased from 7.1 MBOE per day in 1992 to over 12.0 MBOE per day in December 1996. The Company added 15.9 MMBOE of estimated net proved reserves in 1996, representing a 58% increase for the year, at an average Finding Cost of approximately $3.30 per BOE. In 1996, the Company's estimated net proved reserve additions replaced 422% of production, including 229% from drilling, 144% from property acquisitions and 49% from revisions. The Company's 1997 capital budget of $65.0 million includes (i) $43.0 million for ongoing development and exploration programs in the core operating areas, including three 3-D seismic surveys totaling approximately 90 square miles, (ii) $15.0 million for niche acquisitions of properties and (iii) $7.0 million for high-risk, large-target exploration prospects. The principal offices of the Company are located at 1776 Lincoln Street, Suite 1100, Denver, Colorado 80203 and its telephone number is (303) 861-8140. Business Strategy St. Mary's objective is to build shareholder value through consistent growth in per share reserves, production and the resulting cash flow and earnings. A focused and balanced program of low to medium-risk exploration, development and niche acquisitions in each of its core operating areas is designed to provide the foundation for steady growth while the Company's portfolio of high-risk, large-target exploration prospects each have the potential to significantly increase the Company's reserves and production. Principal elements of the Company's strategy are as follows. Focused Geographic Operations. The Company focuses its exploration, development and acquisition activities in five core operating areas where it has built a balanced portfolio of proved reserves, development drilling opportunities and high-risk large-target exploration prospects. Since 1992 St. Mary has expanded its technical and operating staff and increased its drilling, production and operating capabilities. Senior technical managers, each with over 25 years of experience, are based in regional offices located near core properties and are supported by centralized administration in the Company's Denver office. The Company believes that its long-standing presence, its established networks of local industry relationships and its strategic acreage holdings in its core operating areas provide a significant competitive advantage. In addition, the Company believes that its prior investment in experienced technical and managerial personnel will facilitate the expansion of its operations without the need to significantly increase overhead costs. Exploitation and Development of Existing Properties. The Company uses its comprehensive base of geological, geophysical, engineering and production experience in each of its core operating areas to source ongoing, low to medium-risk development and exploration programs. St. Mary conducts detailed geologic studies and uses seismic imaging and advanced well completion techniques to maximize the potential of its existing properties. For example, in 1996 the Company had a significant exploration success in the Box Church Field in east Texas which added 26.4 Bcf of estimated net proved reserves. During 1996, the Company participated in 117 domestic gross wells with an overall 82% success rate. -4- Large-Target Prospects. The Company invests 10% to 15% of its annual capital budget in high-risk, large-target exploration projects and currently has an inventory of eight such projects in its core areas in various stages. The Company's strategy is to test one or more of these large exploration targets each year while furthering the development of early-stage projects and continuing the evaluation of potential new exploration prospects. St. Mary seeks to invest in a diversified mix of large-target exploration projects and generally limits its capital exposure by participating with other experienced industry partners. The Company expects that three of its deep gas prospects in south Louisiana will be drilled and tested during 1997, including its South Horseshoe Bayou prospect which reached its target depth of 19,000 feet in January and was completed and initially tested in February. Selective Acquisitions. The Company seeks to make selective niche acquisitions of properties which complement its existing operations, offer economies of scale and provide further development and exploration opportunities based on proprietary geologic concepts. Management believes that the Company's focus on smaller, negotiated transactions where the Company has specialized geologic knowledge or operating experience has enabled it to acquire attractively-priced and under-exploited properties. During the last three years, the Company completed 21 acquisitions totaling $41.5 million at an average acquisition cost of $3.89 per BOE. Strategic Relationships. The Company has historically cultivated strategic partnerships with independent oil and gas operators having specialized experience and technical skills. The Company's strategy is to serve as operator or alternatively to maintain a majority interest in such ventures to ensure that it can exercise significant influence over development and exploration activities. In addition the Company seeks industry partners who are willing to co-invest on substantially the same basis as the Company. For example, the Company's operations in the Williston Basin are conducted through Panterra Petroleum ("Panterra") in which St. Mary holds a 74% general partnership interest. The managing partner of Panterra is Nance Petroleum Corporation, the principal of which has over 25 years of experience in the Williston Basin. Significant Developments Since December 31, 1995 Follow-on Equity Offering. On February 26, 1997 St. Mary closed the sale by the Company of 2,000,000 shares of common stock at $25.00 per share. The sale of an additional 180,000 shares was closed on March 12, 1997 pursuant to the exercise of the underwriters' over-allotment option. Total net proceeds of the offering of approximately $51.3 million will be used to fund the Company's exploration and development activities and potential acquisitions and for general corporate purposes. Credit Facility. On April 1, 1996, the Company amended and restated its Credit Facility with two banks to provide a $60 million collateralized three-year revolving loan facility which thereafter converts at the Company's option to a five-year term loan. The amount which may be borrowed from time to time will depend upon the value of the Company's oil and gas properties and other assets. The Company's borrowing base, which is redetermined annually, was increased in February, 1997 to $60 million based on the increase in the Company's estimated net proved reserves in 1996. Effective April 1, 1997 the Company has reduced this commitment until the next redetermination to $10 million. Russian Joint Venture. In order to focus on development and exploration efforts in its five core operating areas, the Company decided in 1996 to sell its interests in properties in Russia ("Russian joint venture"). As a result of the closing of this sale which occurred on February 12, 1997, the Company received cash consideration of approximately $5.2 million, approximately $1.7 million of common stock in Ural Petroleum Corporation ("UPC") and a receivable in a form equivalent to a retained production payment of approximately $10.3 million plus interest at 10% per annum. See " Properties--International Operations." -5- Acquisitions of Oil and Gas Properties. In 1996 the Company completed eleven acquisitions of oil and gas properties for $21 million, including an expansion of the Company's interests in the Permian Basin of New Mexico and west Texas through the acquisition of a 90% interest in the oil and gas properties of Siete Oil and Gas Company for $10 million. Oil and Gas Property Sales. In order to continue to focus its development and exploration activities, in 1996 the Company sold certain non-core oil and gas properties in Wyoming and realized a net gain of approximately $2.3 million. Personnel. In May 1996 David L. Henry joined the Company as Vice President of Finance and Chief Financial Officer and in August 1996 Douglas W. York was hired as Vice President of Acquisitions and Reservoir Engineering. ITEM 2. PROPERTIES Domestic Operations The Company's exploration, development and acquisition activities are focused in five core operating areas: the Mid-Continent region; the ArkLaTex region; south Louisiana; the Williston Basin in North Dakota and Montana; and the Permian Basin in west Texas and New Mexico. Set forth below is information concerning each of the Company's major areas of operations based on the Company's estimated net proved reserves as of December 31, 1996.
Oil Gas MBOE PV-10 Value ------- ------ ------------------- ------------------------ (MBbls) (MMcf) Amount Percent (In thousands) Percent ------- ------ ------ ------- -------------- ------- Mid-Continent Region........... 628 61,806 10,929 34.3% $113,466 38.3% ArkLaTex Region................ 1,066 44,684 8,513 26.7% 89,740 30.3% Williston Basin................ 5,648 3,734 6,270 19.7% 46,006 15.5% South Louisiana................ 230 7,386 1,461 4.6% 19,424 6.6% Permian Basin.................. 2,980 4,150 3,672 11.5% 19,499 6.6% Other(1)....................... 139 5,297 1,022 3.2% 8,326 2.7% ------ ------- ------ ------ -------- ------ Total.......................... 10,691 127,057 31,867 100.0% $296,461 100.0% ====== ======= ====== ====== ======== ====== - ----------- (1) Excludes amounts attributable to the Company's Russian joint venture. On February 12, 1997, the Company sold its Russian joint venture. See "International Operations."
Mid-Continent Region. The Company has been active in the Mid-Continent region since 1973 where the Company's operations are managed by its 25-person, Tulsa, Oklahoma office. The Company has ongoing exploration and development programs in the Anadarko Basin of Oklahoma and the Sherman-Marietta Basin of southern Oklahoma and northern Texas. The Mid-Continent region accounted for 34% of the Company's estimated net proved reserves as of December 31, 1996 or 10.9 MMBOE (92% proved developed and 94% gas). The Company participated in 75 gross wells and recompletions in this region in 1996, including 17 Company-operated wells. The Company's 1997 Mid-Continent capital budget of $26.5 million is divided between low-risk exploration and development of the Granite Wash formation, medium to high-risk prospects in the Red Fork and Upper and Lower Morrow sands and continued exploration and development in the Sherman-Marietta Basin. In addition, the Company has a 24.0% working interest in a large-target prospect in the Cotton Valley Reef play of east Texas. The Company has arranged commitments for three drilling rigs in the Mid-Continent region throughout 1997 and plans to drill 25 to 30 wells to be operated by the Company and participate in an additional 30 wells to be operated by other entities. -6- Anadarko Basin. An extensive geologic study of the Granite Wash formation in Washita and Beckham Counties, Oklahoma, undertaken by the Company in 1993 and 1994, has led to an ongoing, multi-year development program. Enhanced understanding of the subsurface geology and application of advanced well completion techniques have enabled the Company to exploit by-passed oil and gas reserves and to improve reservoir recoveries. In 1995 and 1996 the Company drilled or participated in a total of 28 gross wells in the Granite Wash, with an overall 94% success rate. The Company's 1997 capital budget provides for continuation of the Granite Wash program. The Company's activities in the Granite Wash are balanced and complemented by its strategy to drill prospects, particularly in the Red Fork and Upper and Lower Morrow formations in Beckham and Roger Mills Counties, Oklahoma. These prospects target reserves at depths ranging from 15,000 to 18,000 feet. St. Mary operated or participated in three successful completions of exploratory wells in the Morrow channel sands during 1996 and approximately one-half of the Company's 1997 Mid-Continent exploration and development budget is allocated to these Red Fork and Morrow prospects. Sherman-Marietta Basin. In the geologically complex Sherman-Marietta Basin the Company has established a significant acreage position in Cooke and Grayson Counties, Texas in partnership with an independent operator with extensive experience in the area. A twelve square mile 3-D seismic survey at the Company's South Dexter prospect area in 1994 enabled the Company to interpret the area's complex faulting and led to a discovery in the Ordovician Oil Creek sands during 1996. In 1997, the Company plans to continue further exploration in its Red Branch prospect area where it has an approximate 34.1% working interest. The Company continues to lease acreage in the basin and plans additional 3-D projects during 1997 and 1998. See "Large-Target Exploration Projects." Cotton Valley Reef Play. Within its inventory of large-target prospects, the Company holds a 24.0% working interest in 10,060 acres in Leon County, Texas in the rapidly developing Cotton Valley pinnacle reef play. The Company's Carrier Prospect acreage is located approximately nine miles east of the trend of the industry's initial prolific reef discoveries and targets potentially larger reefs that are postulated to have developed in the deeper waters of the basin during the Jurassic period. The Company has identified a large structural anomaly on its acreage at a depth of approximately 17,000 feet based on interpretation of existing 2-D seismic data and, together with its partners, plans to conduct a 52 square mile 3-D seismic survey in 1997. The Company expects to complete processing and interpretation of the seismic data and final evaluation of the prospective acreage by the end of 1997. See "Large-Target Exploration Projects." ArkLaTex Region. The Company's operations in the ArkLaTex area are managed by the Company's 12-person office in Shreveport, Louisiana. In 1992 the Company acquired the ArkLaTex oil and gas properties of T. L. James & Company, Inc. as well as rights to over 6,000 miles of proprietary 2-D seismic data in the region. St. Mary's holdings in the ArkLaTex region are comprised of interests in approximately 450 producing wells, including 51 Company-operated wells, and interests in approximately 1,235 leases totaling approximately 46,000 gross acres and 193 mineral servitudes totaling approximately 20,400 gross acres. Since 1992, the Company has completed eight additional acquisitions of producing properties in the region totaling $6.5 million and has undertaken an active program of additional development and exploration in the ArkLaTex area. The ArkLaTex area accounted for 27% of the Company's estimated net proved reserves as of December 31, 1996 or 8.5 MMBOE (58% proved developed and 87% gas). Activity in the Company's Shreveport office has increased substantially from participation in six wells during 1995 to participation in 22 wells and six workovers and recompletions during 1996, including eleven Company-operated wells. The Company's 1997 capital budget provides for approximately $7.5 million for ongoing development, including continuation of a significant Company-operated development program at its Box Church Field in east Texas. In 1994 and 1995 the Company extended the Bayou D'Arbonne Field in Union Parish, Louisiana with a total of six successful wells in the Cotton Valley Sand formation. In addition, following the Company's discovery in 1995 at the Haynesville Field in Clairborne Parish, Louisiana, St. Mary drilled three successful offset wells in the Haynesville sands during 1996. Three additional wells are planned at Haynesville in 1997. -7- Box Church Field. The Company and its partner acquired the Box Church Field (approximately 2,112 gross acres) in Limestone County, Texas in four separate transactions during 1995 and 1996. The Company's net acquisition cost totaled $2.6 million, and the Company operates and holds an average 58% working interest in three units comprising this field. At the time of the acquisition of the Box Church Field, production was from the Smackover formation at depths below 10,000 feet. Since acquiring this field, St. Mary has increased production from the Smackover formation from approximately 2.5 MMcf per day to over 5.0 MMcf per day in December 1996. During 1996, the Company made a significant exploration discovery in the Box Church Field in the Upper and Lower Travis Peak (approximately 7,500 feet) and Cotton Valley formations (approximately 9,000 feet). The discovery well encountered 200 feet of pay in the Upper and Lower Travis Peak formations. The well was completed in the Cotton Valley formation with multiple behind pipe zones in the Travis Peak formations. During 1996, the Company drilled five development wells, of which four were completed in the Cotton Valley formation and the fifth well is currently undergoing completion in the Travis Peak formation. In addition, the Company re-completed a previously drilled well in the Cotton Valley formation and is currently drilling a fifth Cotton Valley well. This exploration and development program in 1996 resulted in the addition of 26.4 Bcf of estimated net proved reserves as of December 31, 1996, approximately 73% of which are classified as proved undeveloped. Average daily gross production during December 1996 for the Cotton Valley and Travis Peak wells was over 16 MMcf per day. During 1997 and 1998, the Company plans to drill seven Cotton Valley and five Travis Peak wells to fully develop this field. The Company has arranged a commitment for a drilling rig throughout 1997 and expects to drill approximately one well per month at an anticipated completed per well cost of $850,000. South Louisiana Region. The Company's operations in south Louisiana include its royalty interests in St. Mary Parish and a number of large-target prospects located both on its fee lands and in separate prospect areas in south Louisiana. The south Louisiana region accounted for 5% of the Company's estimated net proved reserves as of December 31, 1996 or 1.5 MMBOE (100% proved developed, 84% gas). Fee Lands. The Company owns approximately 24,900 acres of fee lands and associated mineral rights in St. Mary Parish, located approximately 85 miles southwest of New Orleans. St. Mary also owns a 25% working interest in approximately 300 acres located offshore and immediately south of the Company's fee lands. Since the initial discovery on the Company's fee lands in 1938, which established the Horseshoe Bayou Field, cumulative oil and gas revenues, primarily landowner's royalties, to the Company from its south Louisiana properties have exceeded $200 million. St. Mary owns royalty interests on these lands, including production from the Bayou Sale, Horseshoe Bayou and Belle Isle Fields on its fee lands. Approximately 15,500 acres are leased or subject to lease options and 9,400 acres are presently unleased. The Company's principal lessees are Texaco, Vastar and Oryx. Since 1994, several factors have contributed to renewed development and exploration activity on the Company's fee lands. In 1991 the Company's lessees conducted two separate 3-D seismic surveys over portions of the Company's fee properties. Subsequent interpretation of this data by the lessees has contributed to expanded drilling activity in 1995 and 1996 on the Company's fee lands, including successful completion of seven new wells, 31 recompletions and 18 workovers during this two year period. In addition, during the same time period, St. Mary undertook an independent geological and engineering review of its fee properties and developed a -8- comprehensive technical data base. Based on this study the Company has encouraged development by its lessees, facilitated the development of new prospects on acreage not held by production and stimulated exploration interest in deeper, untested horizons. These expanded activities, particularly at the Belle Isle Field, have together largely offset the natural decline rate of the existing production on the Company's fee lands during the past several years with net production increasing by 16% in 1996. The Company's fee properties currently have gross production of over 60 MMcf per day and 2.9 MBbls per day and contributed approximately $8.6 million, or 15%, of St. Mary's gross revenues in 1996. St. Mary's independent engineering studies have identified over 70 prospective zones of behind pipe reserves in existing wells on its fee lands. St. Mary's historical presence in southern Louisiana, its established network of industry relationships and its extensive technical database on the area have enabled the Company to assemble an inventory of large-target prospects in the south Louisiana region, including two deep gas prospects which are located on the Company's fee lands and are scheduled to be tested during 1997. The Company believes that a successful deep test on its fee lands, in addition to adding potentially significant reserves to the Company, would likely encourage exploration activity on its fee lands in the largely untested horizons below 15,000 feet. South Horseshoe Bayou Prospect. The South Horseshoe Bayou prospect is located on St. Mary's fee lands in St. Mary Parish and is the first of three significant deep gas tests in the region scheduled for 1997. St. Mary holds an approximate 22.0% royalty interest and a 25.0% working interest, resulting in an approximate 40% net revenue interest in this 3-D seismic-defined test of the Rob and Operc sands at depths between 17,000 and 19,000 feet. On February 18, 1997 the Company announced that the South Horseshoe Bayou discovery had reached total depth of 19,000 feet, had been completed in the uppermost pay zone below 17,300 feet and was testing directly into the sales line. In initial production tests the well was producing 20 MMcf and 200 Bbls of condensate per day. See "Large-Target Exploration Projects." Mustang Sale Prospect. St. Mary holds an approximate 12.5% royalty interest in the Mustang Sale prospect which is also located on the Company's south Louisiana fee lands. This 3-D seismic-defined prospect was spud in February 1997 and is scheduled to test two Rob C sands on an untested fault block at a depth of approximately 16,000 feet. See "Large-Target Exploration Projects." Roanoke Prospect. St. Mary and its partners control approximately 8,800 gross acres at the Roanoke Prospect in Jefferson Davis Parish through a combination of seismic permits, options and leases. The Roanoke Field, originally discovered in 1934, has produced over 25 MMBbls of oil and 100 Bcf of gas and is considered by the Company to be an excellent candidate for re-evaluation using modern 3-D seismic imaging. The Company holds a 33.3% working interest in the prospect and is targeting potential by-passed pays and untested fault blocks in this mature, complexly faulted salt dome field. In late 1995 the Company conducted a 31 square mile 3-D seismic survey and completed processing and interpretation of the seismic data during 1996. The first prospect was spud in January 1997 and current drilling indicates there are multiple pays, including the Frio and Hackberry sands, on an untested fault block. See "Large-Target Exploration Projects." Patterson Prospect. The Company's Patterson prospect is located to the north of the Company's fee lands in St. Mary Parish. St. Mary holds a 25.0% working interest in leases and options totaling approximately 5,000 acres in the prospect area which lies within a major east-west producing trend between the Garden City and Patterson Fields. In 1995 the Company and its partners drilled an unsuccessful 19,000 foot test based on 2-D seismic data and existing well control. St. Mary and its partners believe that the prospect area remains prospective in several lower Miocene zones, including the Marg and Siph Davisi formations, and the group will participate in a 20 square mile 3-D seismic survey in early 1997 to further delineate this prospect. See "Large-Target Exploration Projects." Atchafalaya Bay Prospect. The Company (40% working interest) and a partner were recently awarded seven tracts (2,845 gross acres) in a Louisiana state lease sale. This is a 3-D seismic play approximately one mile south of the Company's South Horseshoe Bayou discovery. One well is expected to be spud before the end of 1997. See "Large-Target Exploration Projects." -9- Williston Basin Region. The Company's operations in the Williston Basin are conducted through Panterra which was formed in June 1991. The Company holds a 74% general partnership interest in Panterra and the managing partner, Nance Petroleum Corporation ("Nance Petroleum"), owns a 26% interest. Nance Petroleum's principal activity is the management of Panterra's interest in the Williston Basin. All of St. Mary's and Nance Petroleum's activities in the Williston Basin are conducted through Panterra, which currently owns interests in 360 producing wells, including 60 Panterra-operated wells located in 60 fields within the basin's core producing area. The Williston Basin region accounted for 20% of the Company's estimated net proved reserves as of December 31, 1996 or 6.3 MMBOE (93% proved developed and 90% oil). Since 1991 the Company's investment in Panterra has included participation in 11 Panterra-operated development and exploration wells with a 100% success rate. St. Mary has budgeted approximately $6 million as its share of Panterra's 1997 development and exploration program which includes five Panterra-operated wells. The Company's exploration and development activities in the Williston Basin have focused on the application of 3-D seismic data to delineate structural and stratigraphic features which were not previously discernible using conventional 2-D seismic. In 1994 the Company conducted a 4.5 square-mile 3-D seismic survey at the North Bainville Field in Roosevelt County, Montana. This survey led to the successful 1995 extension to the field in the Red River formation. During 1996 the Company completed an additional four wells at North Bainville and completed an additional 21 square mile 3-D seismic survey. Panterra has increased gross production at North Bainville from approximately 330 Bbls per day in 1991 to over 2,000 Bbls per day at the end of 1996. Three additional wells are planned in the North Bainville area in 1997. The Company has begun to apply the experience gained at North Bainville to several other fields in the Williston Basin where the Company holds significant leasehold interests. In late 1995 and 1996 3-D seismic surveys were conducted over the Brush Lake and Nameless Fields in Sheridan County, Montana and McKenzie County, North Dakota respectively. During 1996 the Company completed two successful Red River tests at Brush Lake. Two additional wells are planned at the Brush Lake and Nameless fields in 1997. Permian Basin Region. The Permian Basin of New Mexico and west Texas is the Company's newest area of concentration. Management believes that its Permian Basin operations provide St. Mary with a solid base of long lived oil reserves, promising longer term exploration and development prospects and the potential for secondary recovery projects. The Company established a presence in the basin in 1995 through the acquisition of a 21.2% working interest in a top lease in Ward and Winkler Counties, Texas which is believed to have significant deep exploration potential in the virtually untested deeper formations on the 30,450 acre lease. The Company expanded its holdings in the basin during 1996 with the acquisition of a 90% interest in the producing properties of Siete Oil & Gas Corporation for $10.0 million. The Permian Basin region accounted for 12% of the Company's estimated net proved reserves as of December 31, 1996 or 3.7 MMBOE (96% proved developed and 81% oil). Ward Estes. The Company acquired a 21.2% interest in the top lease in the Ward Estes North Field in Ward County, Texas for $1.7 million in 1995. The top lease covers 30,450 contiguous acres and becomes effective in August 2000 when the existing base lease expires. Rights to all remaining production from the leasehold will transfer to St. Mary and its partners in August 2000. Wells covered by the base lease currently produce in excess of 4.0 MBbls per day from relatively shallow formations and are expected to have significant remaining reserves when the base lease expires. Recent engineering studies indicate that the expanded application of a carbon dioxide flood is economic at current oil prices. Although the deeper Siluro-Devonian and Ellenburger horizons have yielded significant production from several large fields in the immediate area, these deeper formations remain essentially untested on the Ward Estes lease. The Company believes that the top lease provides it with the unusual combination of a low-risk acquisition of long-lived oil reserves and a long term, large-target exploration project. See "Large- Target Exploration Projects." -10- Siete Properties. In 1996 the Company completed the acquisition of a 90% interest in the oil and gas properties of Siete Oil & Gas Corporation for $10.0 million. The acquisition included approximately 150 wells in southeast New Mexico and west Texas producing from the Yates/Queen, Delaware and Bone Springs sands at depths of between 3,500 and 7,500 feet which are operated by the Company's 10% partner. The acquired reserves are approximately 80% oil and have a reserve life of approximately 15 years. During the balance of 1996 the Company completed a series of follow-on acquisitions of smaller interests in the Siete properties which totaled $1.5 million. Large-Target Exploration Projects. The Company invests approximately 10% to 15% of its annual capital budget in longer-term, high-risk, high-potential exploration projects. During the past several years the Company has assembled an inventory of large potential projects in various stages of development which each have the potential to materially increase the Company's reserves. The Company's strategy is to maintain a pipeline of five to seven of these high-risk prospects and to test one or more targets each year, while furthering the development of early-stage projects and continuing the evaluation of potential new exploration prospects. The Company generally seeks to develop large-target prospects by using its comprehensive base of geological, geophysical, engineering and production experience in each of its focus areas. The large-target projects typically require relatively long lead times before a well is commenced in order to develop proprietary geologic concepts, assemble leasehold positions and acquire and fully evaluate 3-D seismic or other data. The Company seeks wherever appropriate to apply the latest technology, including 3-D seismic imaging, in its prospect development and evaluation so as to mitigate a portion of the inherently higher risk of these exploration projects. In addition, the Company seeks to invest in a diversified mix of exploration projects and generally limits its capital exposure by participating with other experienced industry partners. -11- The following table summarizes the Company's active large-target exploration projects. See also "Properties." St. Mary St. Mary Expected Working Royalty Drilling Project Name Objective Location Interest(1) Interest(2) Date(3) - ------------ --------- -------- ----------- ----------- ------- South Horseshoe completed Bayou Rob, Operc, 19,000' St. Mary Parish, LA 25.0% 22.0% Feb 1997 Mustang Sale Rob, 16,000' St. Mary Parish, LA - 12.5% early 1997 Atchafalaya Bay Rob, Operc, 19,000' Atchafalaya Bay, LA 40.0% _ mid 1997 Roanoke(4) Frio, Hackberry Jefferson Davis Parish, LA 33.3% _ early 1997 Red Branch(4) Oil Creek/Penn Grayson & Cooke 34.1% _ 1997-1998 Counties, TX Patterson(4) Marg, Siph Davisi St. Mary Parish, LA 25.0% _ 1998 Carrier(4) Cotton Valley Reef Leon County, TX 24.0% _ 1998-1999 Ward Estes(4) Siluro-Devonian Ward & Winkler 21.2% _ 2000 and Ellenburger Counties, TX - ----------- (1) Working interests differ from net revenue interests due to royalty interest burdens. (2) Royalty interests are approximate and are subject to adjustment. St. Mary has no capital at risk with respect to its royalty interests. (3) Expected Drilling Date means the period during which the Company anticipates the commencement of drilling and/or testing of an exploratory well. (4) The Company may seek the participation of additional industry partners during the development of a project and accordingly may incur dilution of its working and net revenue interests.
International Operations The Company, through subsidiaries, has interests in Russia, Trinidad and Tobago and Canada. Substantially all of the Company's international proved reserves are in Russia. Russian Joint Venture. Until recently, Chelsea Corporation ("Chelsea"), a wholly-owned, second tier subsidiary of the Company, owned a 36% interest in the Anderman/Smith International - Chernogorskoye Partnership which owns a 50% interest in a venture developing the Chernogorskoye oil field in western Siberia (the "Russian joint venture"). On December 16, 1996, the Company executed an Acquisition Agreement to sell its Russian joint venture to UPC. Closing of the transaction occurred on February 12, 1997. In accordance with the terms of the Acquisition Agreement, Chelsea received cash consideration of approximately $5.2 million, approximately $1.7 million of UPC common stock and a receivable in a form equivalent to a retained production payment of approximately $10.3 million plus interest at 10% per annum from the limited liability company formed to hold the Russian joint venture. Chelsea's receivable is collateralized by the partnership interest sold. Chelsea has the right, subject to certain conditions, to require UPC to purchase Chelsea's receivable from the net proceeds of an initial public offering of UPC common stock or alternatively, Chelsea may elect to convert all or a portion of its receivable into UPC common stock immediately prior to an initial public offering of UPC common stock. Trinidad and Tobago. The Company has entered into an agreement with Conwest Exploration Inc. covering the Company's 281,506 acre onshore exploration and production license in the Caroni Basin, Trinidad and Tobago. The agreement provides that Conwest will pay 100% of the Company's 18.675% commitment to the phase I and optional phase II work programs under the license agreement. The total commitments under the license include 275 km. of 2-D seismic and simultaneous gravity data in phase I, and an additional 100 km. of 2-D seismic and the drilling of two exploratory wells in phase II. The agreement provides for cash payments of $150,000 in 1995 upon signing, $112,500 in February 1996, and $95,700 in February 1997. The Company's interest in the project at the conclusion of the phase II commitments will be 7.47%. -12- Key Relationships The Company has historically cultivated strategic partnerships with independent oil and gas operators having specialized experience and technical skills. The Company's strategy is to serve as operator or alternatively to maintain a majority interest in such ventures to ensure that it can exercise significant influence over development and exploration activities. In addition the Company seeks industry partners who are willing to co-invest on substantially the same basis as the Company. For example, the Company's operations in the Williston Basin are conducted through Panterra in which St. Mary holds a 74% general partnership interest. The managing partner of Panterra is Nance Petroleum Corporation, the principal of which has over 25 years of experience in the Williston Basin. Acquisitions The Company's strategy is to make selective niche acquisitions of oil and gas properties within its core operating areas in the United States. The Company seeks to acquire properties which complement its existing operations, offer economies of scale and provide further development and exploration opportunities based on proprietary geologic concepts or advanced well completion techniques. Management believes that the Company's success in acquiring attractively-priced and under-exploited properties has resulted from its focus on smaller, negotiated transactions where the Company has specialized geologic knowledge or operating experience. Although the Company periodically evaluates large acquisition packages offered in competitive bid or auction formats, the Company has continued to emphasize acquisitions having values of less than $10 million which generally attract less competition and where the Company's technical expertise, financial flexibility and structuring experience affords a competitive advantage. The Company seeks acquisitions that offer additional development and exploration opportunities such as its series of acquisitions in the Box Church Field of east Texas during 1995 and 1996. During each of the three years ending December 31, 1996, the Company engaged in a number of acquisition transactions. During 1994, the Company completed four acquisitions totaling $12.4 million. During 1995 and 1996, the Company purchased six parcels for $8.1 million and eleven parcels for $20.9 million, respectively. The Company has budgeted $15.0 million in 1997 for property acquisitions. Reserves At December 31, 1996, Ryder Scott, independent petroleum engineers, evaluated properties representing approximately 81.5% of PV-10 Value and the Company evaluated the remainder. The PV-10 Values shown in the following table are not intended to represent the current market value of the estimated net proved oil and gas reserves owned by the Company. Neither prices nor costs have been escalated, but prices include the effects of hedging contracts. -13- The following table sets forth summary information with respect to the estimates of the Company's net proved oil and gas reserves for each of the years in the three-year period ended December 31, 1996, as prepared by Ryder Scott and by the Company. As of December 31, ------------------ 1996 1995 1994 ---- ---- ---- Reserve Data: (1) Oil (MBbls)........................ 10,691 7,509 6,667 Gas (MMcf)......................... 127,057 75,705 62,515 MBOE............................... 31,867 20,127 17,096 PV-10 value (in thousands)......... $296,461 $120,192 $84,688 Proved developed reserves.......... 84% 89% 93% Production replacement............. 422% 203% 207% Reserve life (years)............... 8.4 6.5 5.6 - ----------- (1) Reserve data attributable to the Company's Russian joint venture have been excluded from this table. Effective February 12, 1997, the Company sold its Russian joint venture. See "International Operations." Production The following table summarizes the average net daily volumes of oil and gas produced from properties in which the Company held an interest during the periods indicated. Year Ended December 31, ----------------------- 1996 1995 1994 ---- ---- ---- Operating Data: (1) Net production: Oil (MBbls).............................. 1,186 1,044 937 Gas (MMcf)............................... 15,563 12,434 12,577 MBOE..................................... 3,780 3,116 3,033 Average net daily production: Oil (Bbls)............................... 3,240 2,852 2,567 Gas (Mcf)................................ 42,522 33,973 34,458 BOE...................................... 10,327 8,514 8,310 Average sales price: (2) Oil (per Bbl)............................ $18.64 $16.37 $14.95 Gas (per Mcf)............................ $ 2.23 $1.56 $1.93 Additional per BOE data: Lease operating expense.................. $2.28 $2.49 $2.54 Production taxes......................... $1.13 $0.93 $0.92 - ----------- (1) Excludes operating data attributable to the Company's Russian joint venture. (2) Includes the effects of the Company's hedging activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Overview." The Company uses financial hedging instruments, primarily fixed-for-floating price swap agreements with financial counterparties, to manage its exposure to fluctuations in commodity prices. The Company also employs limited use of exchange-listed financial futures and options as part of its hedging program for crude oil. -14- Productive Wells The following table sets forth information regarding the number of productive wells in which the Company held a working interest at December 31, 1996. Productive wells are either producing wells or wells capable of commercial production although currently shut in. One or more completions in the same bore hole are counted as one well. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production. Domestic International Total --------------- ------------- --------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Oil 529 136 34 6 563 142 Gas 884 105 - - 884 105 ----- --- --- -- ----- --- Total 1,413 241 34 6 1,447 247 ===== === === == ===== === Drilling Activity The following table sets forth the wells in which the Company participated during each of the three years indicated.
Year Ended December 31, ----------------------- 1996 1995 1994 -------------- -------------- -------------- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Domestic: Development: Oil.............................. 17 3.91 6 1.52 4 1.07 Gas.............................. 74 13.29 38 7.75 30 4.91 Non-productive................... 11 2.70 6 2.00 3 0.33 --- ----- -- ----- -- ----- Total........................ 102 19.90 50 11.27 37 6.31 === ===== == ===== == ===== Exploratory: Oil.............................. - - 5 1.56 1 0.25 Gas.............................. 5 1.25 8 0.74 14 2.26 Non-productive................... 10 3.10 16 4.19 19 3.82 --- ----- -- ----- -- ---- Total........................ 15 4.35 29 6.49 34 6.33 === ===== == ===== == ===== Farmout or non-consent 9 - 4 - 7 - === ===== == ===== == ===== International: Development: Oil.............................. 22 3.96 5 0.90 13 1.28 Gas.............................. - - 1 0.06 2 0.07 Non-productive................... - - - - 2 0.02 --- ----- -- ----- -- ----- Total........................ 22 3.96 6 0.96 17 1.37 === ===== == ===== == ===== Exploratory: Oil.............................. - - - - - - Gas.............................. - - - - 1 0.05 Non-productive................... - - - - 1 0.09 --- ----- -- ----- -- ----- Total........................ - - - - 2 0.14 === ===== == ===== == ===== Farmout or non-consent - - - - - - === ===== == ===== == ===== Grand Total(1) ................... 148 28.21 89 18.72 97 14.15 === ===== == ===== == ===== - ---------- (1) Does not include 6, 4 and 3 gross wells completed on the Company's fee lands during 1994, 1995 and 1996, respectively.
-15- All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment. Domestic and International Acreage The following table sets forth the gross and net acres of developed and undeveloped domestic oil and gas leases, fee properties, mineral servitudes and lease options held by the Company as of December 31, 1996. Undeveloped acreage includes leasehold interests which may already have been classified as containing proved undeveloped reserves.
Developed Acreage Undeveloped Acreage (1) Acreage (2) Total ------------------- ------------------- ------------------- Gross Net Gross Net Gross Net ------- ------- ------- ------- ------- ------- Domestic: Arkansas............................... 4,274 585 167 40 4,441 625 Louisiana.............................. 28,098 7,612 9,210 1,530 37,308 9,142 Montana................................ 11,299 7,341 26,009 20,571 37,308 27,912 New Mexico............................. 3,960 1,038 4,160 1,340 8,120 2,378 North Dakota........................... 27,627 11,129 57,561 20,349 85,188 31,478 Oklahoma............................... 109,476 19,773 53,179 13,402 162,655 33,175 Texas.................................. 49,745 9,672 56,050 10,003 105,795 19,675 Other.................................. 16,814 5,483 147,414 59,063 164,228 64,546 ------- ------- ------- ------- ------- ------- Subtotal........................... 251,293 62,633 353,750 126,298 605,043 188,931 ------- ------- ------- ------- ------- ------- Louisiana Fee Properties............... 12,735 12,735 12,179 12,179 24,914 24,914 Louisiana Mineral Servitudes........... 10,584 5,822 5,511 5,191 16,095 11,013 Louisiana Lease Options................ - - 5,852 1,951 5,852 1,951 ------- ------- ------- ------- ------- ------- Subtotal........................... 23,319 18,557 23,542 19,321 46,861 37,878 ------- ------- ------- ------- ------- ------- Total.............................. 274,612 81,190 377,292 145,619 651,904 226,809 ------- ------- ------- ------- ------- ------- International (3) Canada................................. 6,400 281 32,640 1,131 39,040 1,412 Trinidad and Tobago.................... - - 281,506 21,029 281,506 21,029 ------- ------- ------- ------- ------- ------- Total.............................. 6,400 281 314,146 22,160 320,546 22,441 ------- ------- ------- ------- ------- ------- Grand Total............................. 281,012 81,471 691,438 167,779 972,450 249,250 ======= ======= ======= ======= ======= ======= - ----------- (1) Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of the Company's properties that include multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above. (2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains estimated net proved reserves. (3) Excludes 46,373 gross acres and 8,347 net acres in the Russian Republic. Effective February 12, 1997, the Company sold its Russian joint venture. See "International Operations."
Non-Oil and Gas Activities Summo Minerals. Through December 31, 1996, St. Mary Minerals Inc. ("St. Mary Minerals"), a wholly-owned subsidiary of the Company, has invested a total of approximately $5.6 million and has acquired a total of 9,644,093 common shares of Summo Minerals Corporation ("Summo Minerals") representing 49% of the issued and outstanding common shares and 6,261,000 warrants to purchase common shares, exercisable at prices between Cdn $1.10 and Cdn $1.21 and which expire between October 17, 1997 and October 17, 1998. Summo Minerals is a development-stage, publicly-traded Canadian based mining company engaged in the development of medium-sized copper deposits in the United States and its common shares are listed on the Toronto and the Vancouver stock exchanges under the symbol "SMA". The Company's investment in Summo Minerals had a market value of $8.4 million at December 31, 1996. -16- Summo Minerals' recent activities have focused on the development of its Lisbon Valley property comprised of approximately 5,940 acres of unpatented mining claims and mineral leases located approximately 45 miles southeast of Moab, Utah in San Juan County. Summo Minerals is in the development stage and plans to raise funds to commence operations through debt and equity financings in 1997. The Company currently expects to invest no more than $2.0 million in 1997 in Summo Minerals. It is possible that the Company may elect to exercise some or all of its warrants in order to ultimately realize the amount of any appreciation in the value of the warrants. The Company currently intends to exercise such warrants if the common share price is substantially in excess of the warrant price. The total cash payment in connection with such exercise would be approximately $3.1 million. There can be no assurance that the Company will realize a return on its investment in Summo Minerals. Competition Competition in the oil and gas business is intense, particularly with respect to the acquisition of producing properties, proved undeveloped acreage and leases. Major and independent oil and gas companies actively bid for desirable oil and gas properties and for the equipment and labor required for their operation and development. The Company believes that the locations of its leasehold acreage, its exploration, drilling and production capabilities and the experience of its management and that of its industry partners generally enable the Company to compete effectively. Many of the Company's competitors, however, have financial resources and exploration and development budgets that are substantially greater than those of the Company, and these may adversely affect the Company's ability to compete, particularly in regions outside of the Company's principal producing areas. Because of this competition, there can be no assurance that the Company will be successful in finding and acquiring producing properties and development and exploration prospects at its planned capital funding levels. Markets and Major Customers Substantially all of the Company's oil and gas production is sold on the spot market. During 1996, sales to an individual customer constituted 17.3% of total revenues. There were no oil and gas customers of the Company that represented more than 10% of its oil and gas revenues in 1995 or 1994. Government Regulations The Company's business is subject to various federal, state and local laws and governmental regulations which may be changed from time to time in response to economic or political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental protection. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. The Company's operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. The Company could be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on the Company's financial condition and results of operations. The Company maintains insurance coverage for its operations, including limited coverage for sudden environmental damages, but does not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, the Company does not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages is available at a reasonable cost. Accordingly, the Company may be subject to liability or may lose substantial portions of its properties in the event of certain environmental damages. The Company could incur substantial costs to comply with environmental laws and regulations. -17- The Oil Pollution Act of 1990 imposes a variety of regulations on "responsible parties" related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a material adverse impact on the Company. The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been introduced in Congress that would reclassify certain exploration and production wastes as "hazardous wastes" which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. Title to Properties Substantially all of the Company's domestic working interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of drilling operations on properties. The Company has obtained title opinions or conducted a thorough title review on substantially all of its producing properties and believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The Company's properties are subject to customary royalty interests, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. Substantially all of the Company's oil and gas properties are and will continue to be mortgaged to secure borrowings under the Company's credit facilities. The Company performs only a minimal title investigation before acquiring undeveloped properties. The Company relies upon sovereign ownership of rights granted under license or concession agreements by foreign governments and conducts no independent title investigation. Concession negotiations generally are undertaken through local legal counsel to ensure compliance with local laws. In the event the Company acquires previously granted rights to explore for, develop or produce oil or gas in a foreign country, it generally relies on local legal counsel for the title work. Operational Hazards and Insurance The oil and gas business involves a variety of operating risks, including fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company and operators of properties in which it has an interest maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant unfavorable event not fully covered by insurance could have a material adverse effect on the Company's financial condition and results of operations. Furthermore, the Company cannot predict whether insurance will continue to be available at a reasonable cost or at all. -18- Employees and Office Space As of December 31, 1996, the Company had 96 full-time employees. None of the Company's employees is subject to a collective bargaining agreement. The Company considers its relations with its employees to be good. The Company leases approximately 34,500 square feet of office space in Denver, Colorado, for its executive offices, of which 7,200 square feet is subleased, approximately 12,200 square feet of office space in Tulsa, Oklahoma, approximately 7,300 square feet of office space in Shreveport, Louisiana and approximately 500 square feet in Lafayette, Louisiana. The Company believes that its current facilities are adequate. Glossary The terms defined in this section are used throughout this Form 10-K. 2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a two-dimensional cross section of the subsurface. 3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a three-dimensional picture of the subsurface. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. Bcf. Billion cubic feet, used herein in reference to natural gas. Behind pipe reserves. Estimated net proved reserves in a formation in which production casing has already been set in the wellbore but has not been perforated and production tested. BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves. Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Estimated net proved reserves. The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. -19- Fee land. The most extensive interest which can be owned in land, including surface and mineral (including oil and gas) rights. Finding Cost. Expressed in dollars per BOE, Finding Costs are calculated by dividing the amount of total capital expenditures for oil and gas activities by the amount of estimated net proved reserves added during the same period (including the effect on proved reserves of reserve revisions). Gross acres. An acre in which a working interest is owned. Gross well. A well in which a working interest is owned. MBbl. One thousand barrels of oil or other liquid hydrocarbons. MMBbl. One million barrels of oil or other liquid hydrocarbons. MBOE. One thousand barrels of oil equivalent. MMBOE. One million barrels of oil equivalent. Mcf. One thousand cubic feet. MMcf. One million cubic feet. MMBtu. One million British Thermal Units. A British Thermal Unit is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit. Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells. PV-10 Value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. Productive well. A well that is producing oil or gas or that is capable of production. Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed. Reserve Life. Reserve Life, expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the trailing 12-month period. -20- Royalty. That interest paid to the owner of mineral rights expressed as a percentage of gross income from oil and gas produced and sold unencumbered by expenses. Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and gas production free of costs of exploration, development and production. Royalty interests are approximate and are subject to adjustment. Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated net proved reserves. Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production. ITEM 3. LEGAL PROCEEDINGS While the Company has been named as a defendant in certain lawsuits arising in the ordinary course of business, to the knowledge of management, no claims are pending or threatened against the Company or any of its subsidiaries which individually or collectively could have a material adverse effect upon the Company's financial condition or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the Company's security holders during the fourth quarter of 1996. -21- PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDERS MATTERS Market Information. The Company's common stock is traded on the Nasdaq National Market System under the symbol MARY. The stock began trading December 16, 1992; no market for the stock existed before that date. The range of high and low bid prices for the quarterly periods in 1995 and 1996, as reported by the Nasdaq National Market System, is set forth below: Quarter Ended High Low ------------- ---- --- March 31, 1995 $14.000 $12.500 June 30, 1995 13.625 10.875 September 30, 1995 14.875 12.875 December 31, 1995 15.000 13.250 March 31,1996 16.625 13.500 June 30, 1996 17.875 15.875 September 30, 1996 17.000 14.250 December 31, 1996 27.375 16.500 On March 21, 1997 the closing sale price for the Company's common stock was $25.125 per share. Holders. As of March 21, 1997, the number of record holders of the Company's common stock was 155. Management believes, after inquiry, that the number of beneficial owners of the Company's common stock is in excess of 1,100. Dividends. The Company has paid cash dividends in each of the last 58 consecutive calendar years. Annual dividends of $0.16 per share have been paid quarterly in each of the years 1987 through 1996. These dividends totaled approximately $1,171,000 for the years 1987 through 1992 and $1,402,000 in each of the years 1993 through 1995 and $1,401,000 in 1996. The Company's line of credit agreement with NationsBank and Norwest Bank limits cumulative dividends from December 31, 1992 forward to $3,000,000 plus cumulative net income from December 31, 1991, which totals $38,128,000 at December 31, 1996. The Company increased its quarterly dividend 25% to $.05 per share effective with the quarterly dividend declared in January 1997 and payable February 1997. -22- ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA The following table sets forth selected consolidated financial data for the Company as of the dates and for the periods indicated. The financial data for the five years ended December 31, 1996, were derived from the Consolidated Financial Statements of the Company which have been audited by Coopers & Lybrand L.L.P., independent accountants. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes a discussion of factors materially affecting the comparability of the information presented, and the Company's financial statements included elsewhere in this report.
Year Ended December 31, --------------------------------------------------- 1996 1995 1994 1993 1992 ------- ------- ------- ------- ------- (In thousands, except per share data) Income Statement Data: Operating revenues: Oil production.............................. $22,100 $17,090 $14,006 $13,685 $11,949 Gas production.............................. 34,674 19,479 24,233 24,523 23,296 Gas contract settlements and other.......... 2,777 2,081 6,546 424 15,413 ------- ------- ------- ------- ------- Total operating revenues..................... 59,551 38,650 44,785 38,632 50,658 ------- ------- ------- ------- ------- Operating expenses: Oil and gas production...................... 12,897 10,646 10,496 9,341 7,793 Depletion, depreciation and amortization.... 12,732 10,227 10,134 8,775 6,213 Impairment of proved properties............. 408 2,676 4,219 3,498 1,565 Exploration................................. 8,185 5,073 8,104 5,457 3,615 Abandonment and impairment of unproved properties.............................. 1,469 2,359 1,023 1,020 1,264 General and administrative.................. 7,603 5,328 5,261 4,712 4,544 Gas contract disputes and other............. 78 152 493 638 1,332 (Income) loss in equity investees........... (1,272) 579 348 659 1,026 ------- ------- ------- ------- ------- Total operating expenses..................... 42,100 37,040 40,078 34,100 27,352 ------- ------- ------- ------- ------- Income from operations....................... 17,451 1,610 4,707 4,532 23,306 Non-operating expense........................ 1,951 896 525 62 791 Income tax expense (benefit)................. 5,333 (723) 445 1,065 7,328 ------- ------- ------- ------- ------- Income from continuing operations............ 10,167 1,437 3,737 3,405 15,187 Gain on sale of discontinued operations, net of income taxes........................ 159 306 - - 430 Income before cumulative effect of change in accounting principle.................... 10,326 1,743 3,737 3,405 15,617 Cumulative effect of change in accounting principle.................................. - - - 300 - ------- ------- ------- ------- ------- Net income................................... $10,326 $1,743 $3,737 $3,705 $15,617 ======= ======= ======= ======= ======= Net income per common share: Income from continuing operations........... $1.16 $0.17 $0.43 $0.39 $2.10 Gain on sale of discontinued operations..... 0.02 0.03 - - 0.06 Cumulative effect of change in accounting principle............................... - - - 0.03 - ------- ------- ------- ------- ------- Net income per share......................... $1.18 $0.20 $0.43 $0.42 $2.16 ======= ======= ======= ======= ======= Cash dividends per share..................... $0.16 $0.16 $0.16 $0.16 $0.16 Weighted average common shares outstanding 8,759 8,760 8,763 8,763 7,233
-23-
Year Ended December 31, ---------------------------------------------------- 1996 1995 1994 1993 1992 -------- -------- -------- -------- -------- (In thousands, except per share data) Other Data: EBITDA (1)................................. $ 30,183 $11,837 $14,841 $13,307 $29,519 Net cash provided by operating activities.. 24,205 17,713 20,271 19,675 26,989 Capital and exploration expenditures....... 52,601 32,307 31,811 23,434 20,645 Balance Sheet Data (end of period): Working capital............................ $ 13,926 $ 3,102 $ 9,444 $15,187 $17,913 Net property and equipment................. 101,510 71,645 59,655 51,381 46,998 Total assets............................... 144,271 96,126 89,392 81,797 75,896 Long-term debt............................. 43,589 19,602 11,130 7,400 5,000 Total stockholders' equity................. 75,160 66,282 66,034 63,635 61,362 - ----------- (1) EBITDA is defined as income before interest, income taxes, depreciation, depletion and amortization. EBITDA is a financial measure commonly used for the Company's industry and should not be considered in isolation or as a substitute for net income, cash flow provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income and may vary among companies, the EBITDA presented above may not be comparable to similarly titled measures of other companies.
-24- ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview St. Mary was founded in 1908 and incorporated in Delaware in 1915. Since 1992 St. Mary has expanded its technical and operating staff and increased its drilling, production and operating capabilities in its five core operating areas in the United States. The Company's activities in the Williston Basin are conducted through Panterra Petroleum ("Panterra") in which the Company owns a 74% general partnership interest. The Company proportionally consolidates its interest in Panterra. The Company has two principal equity investments, Summo Minerals, a Canadian copper mining company, and, until recently, its Russian joint venture. The Company accounts for its Russian joint venture and investment in Summo Minerals under the equity method and includes its share of the income or loss from these entities. Effective February 12, 1997, the Company sold its Russian joint venture. The Company receives significant royalty income from its Louisiana fee lands. Revenues from the fee lands were $8.1, $5.5 and $6.3 million for the years 1996, 1995 and 1994, respectively. Management expects the Company's royalty income to increase significantly in 1997 with the completion of the St. Mary Land & Exploration No. 2 well at South Horseshoe Bayou in February 1997. This well is flowing in excess of 25 million cubic feet of gas per day. The Company owns a 25% working interest and 22% royalty interest in this well for a combined net revenue interest of approximately 40%. The south Louisiana reserves tend to decline rapidly, therefore management anticipates lower revenue from the Louisiana fee lands in future years unless further exploration and development activity continues to offset the normal production decline of producing properties. The Company has been notified of several geologic objectives the lessees intend to test in 1997 based on 3-D seismic surveys. The 1996 results of operations include several significant acquisitions made during the past few years. The Company purchased an additional interest from a Panterra partner at year-end 1994 increasing its ownership in Panterra to 74%. In December 1995, the Company acquired two different interests in the Box Church Field located in Texas for $2.2 million and several additional interests in 1996 for $580,000. The Company drilled and completed three wells in this field in 1996 which proved the upside potential the Company had identified and added 26.4 billion cubic feet of net gas reserves. The Company plans to drill an additional 13 wells to develop this field in 1997 and 1998. The Company purchased a 90% interest in the producing properties of Siete Oil & Gas Corporation for $10.0 million in June 1996 and completed a series of follow-on acquisitions of smaller interests in the Siete properties totaling $1.5 million. These properties are located in the Permian Basin of New Mexico and west Texas. In October 1996, the Company acquired additional interests from Sonat Exploration Company in its Elk City Field located in Oklahoma for $6.1 million. Several smaller acquisitions were also completed during 1996 totaling $2.8 million. The Company entered into several long-term take-or-pay gas sales contracts in the late 1970s and early 1980s at prices substantially above current market prices. When the purchasers failed to take the volumes required by the contracts and began paying lower market prices, the Company commenced legal proceedings against the purchasers. The Company settled these claims out of court, receiving lump-sum payments as compensation for all prior claims and remaining contract values. The Company has no future obligation to deliver gas to these purchasers. The Company settled the last remaining disputes in 1994 for $5.7 million. As a result of the purchasers' failure to take the required gas, the Company was underproduced approximately 1.6 and 1.9 BCF relative to other working interest owners at December 31, 1996 and 1995, respectively. With all disputes now settled, the Company is selling additional gas and beginning to reduce this imbalance. -25- The Company seeks to protect its rate of return on acquisitions of producing properties by hedging up to the first 24 months of an acquisition's production at prices approximately equal to or greater than those used in the Company's acquisition evaluation and pricing model. The Company also periodically uses hedging contracts to hedge or otherwise reduce the impact of oil and gas price fluctuations on production from each of its core operating areas. The Company's strategy is to ensure certain minimum levels of operating cash flow and to take advantage of windows of favorable commodity prices. The Company generally limits its aggregate hedge position to no more than 50% of its total production. The Company seeks to minimize basis risk and indexes the majority of its oil hedges to NYMEX prices and the majority of its gas hedges to various regional index prices associated with pipelines in proximity to the Company's areas of gas production. The Company has hedged approximately 12% of its estimated 1997 gas production at an average fixed NYMEX equivalent price of $2.12 per MMBtu and approximately 14% of its estimated 1997 oil production at an average fixed NYMEX price of $18.37 per Bbl. The Company has also purchased options resulting in price collars and price floors on approximately 16% of the Company's estimated 1997 oil production with price ceilings between $21 and $27 per Bbl and price floors between $18 and $21 per Bbl. This Annual Report on Form 10-K includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, including such matters as future capital, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, repayment of debt, business strategies, expansion and growth of the Company's operations and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, general economic and business conditions, the business opportunities (or lack thereof) that may be presented to and pursued by the Company, changes in laws or regulations and other factors, many of which are beyond the control of the Company. Readers are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. -26- Results of Operations The following table sets forth selected operating data for the periods and upon the basis indicated:
Year Ended December 31, ------------------------------- 1996 1995 1994 ------- ------- ------- (In thousands, except BOE data) Oil and gas production revenues: Working interests.................................. $48,685 $31,055 $31,896 Louisiana royalties................................ 8,089 5,514 6,343 ------- ------- ------- Total........................................... $56,774 $36,569 $38,239 ======= ======= ======= Net Production: Oil (MBbls)........................................ 1,186 1,044 937 Gas (MMcf)......................................... 15,563 12,434 12,577 ------- ------- ------- MBOE............................................... 3,780 3,116 3,033 ======= ======= ======= Average sales price(1): Oil (per Bbl)...................................... $ 18.64 $ 16.37 $ 14.95 Gas (per Mcf)...................................... $ 2.23 $ 1.56 $ 1.93 Oil and gas production costs: Lease operating expenses........................... $ 8,615 $ 7,747 $ 7,713 Production taxes................................... 4,282 2,899 2,783 ------- ------- ------- Total........................................... $12,897 $10,646 $10,496 ======= ======= ======= Additional per BOE data: Sales price........................................ $ 15.02 $ 11.74 $ 12.61 Lease operating expenses........................... 2.28 2.49 2.54 Production taxes................................... 1.13 .93 .92 ------- ------- ------- Gross operating margin.......................... $ 11.61 $ 8.32 $ 9.15 Depletion, depreciation and amortization........... 3.37 3.28 3.34 Impairment of proved properties.................... .11 .86 1.39 General and administrative......................... 2.01 1.71 1.73 - ----------- (1) Includes the effects of the Company's hedging activities.
Oil and Gas Production Revenues. Oil and gas production revenues increased $20.2 million, or 55% to $56.8 million in 1996 compared to $36.6 million in 1995. Oil production volumes increased 14% while gas production volumes increased 25% in 1996 compared to 1995. Average net daily production reached 10.3 MBOE in 1996 compared to 8.5 MBOE in 1995. This production increase resulted from new properties acquired and drilled during 1995 and 1996. The average realized oil price for 1996 increased 14% to $18.64 per Bbl, while realized gas prices increased 43% to $2.23 per Mcf, from their respective 1995 levels. The Company hedged approximately 70% of its oil production for 1996 or 842 MBbls at an average NYMEX price of $18.92. The Company realized a $2.6 million decrease in oil revenue or $2.20 per Bbl for 1996 on these contracts compared to a $131,000 decrease or $.13 per Bbl in 1995. The Company also hedged 23% of its 1996 gas production or 3,651,000 MMBtu at an average NYMEX price of $2.00. The Company realized a $1.65 million decrease in gas revenues or $.11 per Mcf for 1996 from these hedge contracts compared to a $121,000 increase or $.01 per Mcf in 1995. -27- Oil and gas production revenues declined $1.7 million, or 4% to $36.6 million in 1995 compared to $38.2 million in 1994 due primarily to lower gas prices. Oil production volumes increased 11% while gas production volumes declined 1% in 1995 compared to 1994. Average net daily production reached 8.5 MBOE in 1995 compared to 8.3 MBOE in 1994. This production increase resulted from new properties acquired and drilled during 1995. The average realized oil price for 1995 increased 9% to $16.37 per Bbl, while realized gas prices declined 19% to $1.56 per Mcf, from their respective 1994 levels. The Company hedged approximately 60% of its oil production for 1995 or 605 MBbls at an average NYMEX price of $17.66. The Company realized a $131,000 decrease in oil revenue or $.13 per Bbl for 1995 on these contracts compared to a $67,000 decrease or $.07 per Bbl in 1994. The Company also hedged 6% of its 1995 gas production or 695,000 MMBtu at an average NYMEX price of $1.89. The Company realized a $121,000 increase in gas revenues or $.01 per Mcf for 1995 from these hedge contracts compared to a $51,000 increase in 1994. Oil and Gas Production Costs. Oil and gas production costs consist of lease operating expense and production taxes. Total production costs increased $2.3 million, or 21% in 1996 to $12.9 million compared with $10.6 million in 1995. However, total oil and gas production costs per BOE declined slightly to $3.41 in 1996 compared to $3.42 per BOE in 1995. Oil and gas production costs increased $150,000, or 1% in 1995 to $10.6 million compared with $10.5 million in 1994. However, total oil and gas production costs per BOE declined slightly to $3.42 in 1995 compared to $3.46 per BOE in 1994. Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion and amortization expense ("DD&A") increased $2.5 million, or 24% to $12.7 million in 1996 compared with $10.2 million in 1995. This increase resulted from new properties acquired and drilled in 1996. DD&A expense per BOE increased 3% to $3.37 in 1996 compared to $3.28 in 1995. Impairment of proved oil and gas properties declined $2.3 million or 85% to $408,000 in 1996 compared with $2.7 million in 1995 because of higher oil and gas prices and better development drilling results. The 1995 impairment provision included effects of the adoption of SFAS No. 121 as of October 1, 1995 which resulted in an additional impairment charge for proved properties of $1.0 million in the fourth quarter of 1995. Depreciation, depletion and amortization expense increased slightly to $10.2 million in 1995 compared with $10.1 million in 1994. However, DD&A expense per BOE declined 2% to $3.28 in 1995 compared to $3.34 in 1994. Impairment of proved oil and gas properties declined $1.5 million or 37% to $2.7 million in 1995 compared with $4.2 million in 1994 because high cost marginal wells in newer fields and low year-end gas prices required further ceiling test writedowns in 1994. The 1995 impairment provision included effects of the adoption of SFAS No. 121 as of October 1, 1995 which resulted in an additional impairment charge for proved properties of $1.0 million in the fourth quarter of 1995. Abandonment and impairment of unproved properties declined $890,000 or 38% to $1.5 million in 1996 compared to $2.4 million in 1995 due to the additional impairments taken during 1995. Abandonment and impairment of unproved properties increased $1.4 million or 131% to $2.4 million in 1995 compared to $1.0 million in 1994. The Company recorded an impairment of $1.0 million of leasehold costs in 1995 as a result of several unsuccessful prospects in its drilling program. Exploration. Exploration expense increased $3.1 million or 61% to $8.2 million for 1996 compared with $5.1 million in 1995 as a result of higher exploratory dry hole expense from increased drilling activity and a large 3-D seismic survey conducted in 1996. Exploration expense decreased $3.0 million or 37% to $5.1 million in 1995 compared to $8.1 million in 1994 due to reduced 1995 geophysical activity and better exploratory drilling results in 1995 compared with 1994. General and Administrative. General and administrative expense increased $2.3 million or 43% to $7.6 million for 1996 compared to $5.3 million in 1995 due to higher compensation costs, professional fees and a $1.3 million increase in the expense associated with the Company's SAR plan. General and administrative expenses were unchanged at $5.3 million for 1995 and 1994. Higher compensation costs were offset by lower professional fees and travel costs. -28- Gas contract disputes and other consists of legal expenses in connection with gas contract disputes and the Company's mining activities. This expense declined $74,000 to $78,000 in 1996 compared with 1995 because insurance proceeds were recovered on a previous settlement. This expense declined $341,000 to $152,000 in 1995 compared with 1994 because the mining activities are now conducted through the Company's equity investee, Summo Minerals Corporation. Equity in (Income) Loss of Russian Joint Venture. The Company accounts for this investment under the equity method and includes its share of income or loss from the venture. The equity in the (income) loss of the Russian joint venture was $(1.7) million in 1996, $322,000 in 1995 and $328,000 in 1994. The large increase in 1996 income was due to higher oil production and prices. As discussed under Outlook, the Company sold this investment in February 1997. Equity in Loss of Summo Minerals Corporation. The Company accounts for this investment under the equity method and includes its share of Summo's income or loss. The equity in the loss of Summo was $457,000 in 1996, $257,000 in 1995 and $20,000 in 1994 because of higher general and administrative expenses associated with the expansion of Summo's Denver office. The Company's ownership in Summo was 49% in 1996, 51% in 1995 and 42% in 1994. Non-Operating Income and Expense. Net interest and other nonoperating expense increased $1.1 million to $2.0 million in 1996 compared to $896,000 in 1995 because of additional interest expense associated with higher debt levels. Net interest and other nonoperating expense increased $371,000 to $896,000 in 1995 compared to $525,000 in 1994 because of the interest expense associated with higher debt levels and the Company's increased Panterra ownership. Income Taxes. Income tax expense was $5.3 million in 1996, resulting in an effective 34% tax rate, compared to a net tax benefit of $723,000 for 1995 which reflected the utilization of capital loss carryovers and Section 29 tax credits and income tax expense of $445,000 for 1994. State tax expense was $700,000 in 1996, $396,000 in 1995 and $445,000 in 1994. The 1996 Louisiana taxes increased significantly as a result of higher Louisiana net income. Net Income. Net income for 1996 increased $8.6 million or 492% to $10.3 million compared to $1.7 million in 1995 with higher production volumes and prices resulting in a $20.2 million increase in oil and gas production revenues. This was partially offset by the associated higher production expenses and DD&A, a $3.1 million increase in exploration expense and a $2.3 million increase in general and administrative expenses. The Company also realized a $2.3 million gain on sale of producing properties in 1996 compared to $1.3 million in 1995 and recorded $1.7 million equity income from its Russian joint venture in 1996 compared to an equity loss of $322,000 in 1995. Net income for 1995 declined $2.0 million or 54% to $1.7 million compared to $3.7 million in 1994. Lower 1995 natural gas prices and associated revenue were partially offset by reduced exploration expense and the Company's income tax benefit. The Company also realized a $306,000 gain from the sale of discontinued real estate in 1995 with no comparable activity in 1994. Liquidity and Capital Resources The Company's primary sources of liquidity are cash provided by operating activities and borrowings under its credit facility and the Panterra credit facility. The Company's principal cash needs are for the exploration and development of oil and gas properties, acquisitions and payment of dividends to stockholders. The Company continually reviews its capital expenditure budget based on changes in cash flow and other factors. Cash Flow. The Company's net cash provided by operating activities increased 37% to $24.2 million in 1996 compared to $17.7 million in 1995. An $11.0 million increase in 1996 cash received from oil and gas operations was partially offset by higher exploration expenses, interest expense and income taxes. The Company's net cash provided by operating activities decreased 13% to $17.7 million in 1995 compared to $20.3 million in 1994. A $3.2 million decline in exploration costs for 1995 partially offset the last of the Company's gas contract disputes settled in 1994 for $5.7 million. -29- In the first quarter of 1997, the Company made a cash payment of approximately $1.6 million in satisfaction of liabilities previously accrued by the Company under its SAR plan. The Company will not recognize any additional expense in connection with this payment. Net cash used in investing activities increased 37% to $45.2 million in 1996 compared with $33.0 million in 1995 primarily due to increased capital expenditures and acquisition of oil and gas properties partially offset by $3.1 million in cash received as a result of the purchase of the remaining 35% interest in St. Mary Operating Company and $3.1 million in proceeds from the sale of oil and gas properties. Total capital expenditures, including acquisitions of oil and gas properties, in 1996 increased $17.7 million to $48.5 million compared to $30.8 million in 1995 due to increased drilling activity and $21.0 million of reserve acquisitions compared to $8.1 million spent in 1995. Net cash used in investing activities increased 43% to $33.0 million in 1995 compared with $23.1 million in 1994 primarily due to increased capital expenditures, acquisition of oil and gas properties and the investment in Summo Minerals Corporation, partially offset by $2.3 million in proceeds from the sale of oil and gas properties. Total capital expenditures, including acquisitions of oil and gas properties, in 1995 increased to $30.8 million compared to $22 million in 1994 due to increased drilling activity and reserve acquisitions. The Company invested $4.5 million in Summo Minerals Corporation during 1995 increasing its ownership to 51%. Net cash provided by financing activities increased $15.6 million to $22.6 million in 1996 compared to $7.0 million in 1995. The Company borrowed funds in 1996 for the expanded capital expenditure programs and reserve acquisitions. Net cash provided by financing activities was $7 million in 1995 compared to net cash used by financing activities of $2 million in 1994. The Company borrowed funds in 1995 for its capital expenditure programs and its mining investment compared with debt repayment of $578,000 in 1994. The Company paid dividends of $1.4 million in 1996, 1995 and 1994. The Company increased its quarterly dividend 25% to $.05 per share effective with the quarterly dividend declared in January 1997 and payable February 1997. The Company had $3.3 million in cash and cash equivalents and working capital of $13.9 million as of December 31, 1996 compared to $1.7 million of cash and cash equivalents and working capital of $3.1 million at December 31, 1995. This increase resulted from the cash investments received as part of its St. Mary Operating Company investment, increased oil and gas receivables and classification of its Russian joint venture as a current asset held for sale. Credit Facility. On April 1, 1996, the Company amended and restated its credit facility with two banks to provide a $60.0 million collateralized three-year revolving loan facility which thereafter converts at the Company's option to a five-year term loan. The amount which may be borrowed from time to time will depend upon the value of the Company's oil and gas properties and other assets. The Company's borrowing base, which is redetermined annually, was increased from $40 million to $60.0 million in February 1997 based on the increase in the Company's estimated net proved reserves in 1996. Outstanding revolving loan balances under the Company's credit facility, which were $33.9 million at December 31, 1996, accrue interest at rates determined by the Company's debt to total capitalization ratio. During the revolving period of the loan, loan balances accrue interest at the Company's option of either the banks' prime rate or LIBOR plus 1/2% when the Company's debt to total capitalization is less than 30%, up to a maximum of either the banks' prime rate plus 1/8% or LIBOR plus 1-1/4% when the Company's debt to total capitalization ratio exceeds 50%. The credit facility is collateralized by a mortgage of substantially all of the Company's domestic oil and gas properties. The credit facility provides for, among other things, covenants limiting additional recourse indebtedness of the Company, investments or disposition of assets by the Company and certain restrictions on the payment of cash dividends to holders of the Company's stock. -30- Panterra, in which the Company has a 74% general partnership ownership interest, has a separate credit facility with a $26.0 million borrowing base and $13.1 million outstanding as of December 31, 1996. During February 1997, Panterra agreed to amend the Panterra credit facility to extend the revolving loan period to March 31, 1999 and the maturity of the credit facility to March 31, 2004. The Company intends to use the available credit under the Panterra credit facility to fund a portion of its 1997 capital expenditures in the Williston Basin. Capital and Exploration Expenditures. The Company's expenditures for exploration and development of oil and gas properties and acquisitions are the primary use of its capital resources. The following table sets forth certain information regarding the costs incurred by the Company in its oil and gas activities during the periods indicated. Capital and Exploration Expenditures ------------------------------------ Year Ended December 31, ----------------------- (In thousands) 1996 1995 1994 ------- ------- ------- Development......................... $16,709 $12,625 $ 5,946 Exploration: Domestic.......................... 11,910 8,746 9,481 International..................... 84 (112) 877 Acquisitions: Proved............................ 20,957 8,111 12,279 Unproved.......................... 2,941 2,937 3,228 ------- ------- ------- Total........................... $52,601 $32,307 $31,811 ======= ======= ======= Russian joint venture............... $ 3,881 $ 3,213 $ 1,551 ======= ======= ======= The Company's total costs incurred in 1996 increased 63% to $52.6 million compared to $32.3 million in 1995. Proved property acquisitions increased $12.8 million to $21.0 million in 1996 compared to $8.1 million in 1995. The Company purchased a 90% interest in the producing properties of Siete Oil & Gas Corporation for $10.0 million in June 1996 and completed a series of follow-on acquisitions of smaller interests in the Siete properties which totaled $1.5 million. In October 1996, the Company acquired additional interests from Sonat in its Elk City Field located in Oklahoma for $6.1 million. Several smaller acquisitions were also completed during 1996 totaling $3.4 million. The Company spent $31.6 million in 1996 for unproved property acquisitions and domestic exploration and development compared to $24.3 million in 1995 as a result of the Company's expanded drilling programs. The Company's total costs incurred in 1995 increased 2% to $32.3 million compared to $31.8 million in 1994. Proved property acquisitions declined $4.2 million to $8.1 million in 1995 compared to $12.3 million in 1994. The Company completed several proved property acquisitions in the ArkLaTex area totalling $5.9 million during 1995. In January 1995, the Company acquired a 21% interest in a top lease on the 30,450 acre Ward Estes Field in Texas for $1.7 million. Panterra, in which the Company has a 74% ownership, acquired properties from Adex Resources in 1995 for $547,000. The Company spent $24.3 million in 1995 for unproved property acquisitions and domestic exploration and development compared to $18.7 million in 1994 as a result of the Company's expanded drilling programs. -31- Outlook. The Company believes that its existing capital resources, cash flow from operations and available borrowings are sufficient to meet its anticipated capital and operating requirements for 1997. The Company closed a follow-on common stock offering of 2.18 million shares in February 1997, raising $51.3 million in net proceeds. The proceeds will be used to fund the Company's exploration, development and acquisition programs, and pending such use will be used to repay borrowings under its credit facility. As of March 21, 1997, the Company has repaid all borrowings under its credit facility, and effective April 1, 1997, has reduced the commitment under this facility, until its next redetermination, to $10 million. The Company has the right to increase this commitment between redetermination periods. For 1997, the Company anticipates spending approximately $65.0 million for capital and exploration expenditures with $43.0 million allocated for domestic exploration and development, $15.0 million allocated for domestic property acquisitions and $7.0 million for large-target, high-risk domestic exploration and development. The amount and allocation of future capital and exploration expenditures will depend upon a number of factors including the number of available acquisition opportunities, the Company's ability to assimilate such acquisitions, the impact of oil and gas prices on investment opportunities, the availability of capital and the success of its development and exploratory activity which could lead to funding requirements for further development. The Company, through subsidiaries, owned an 18% interest (the "Russian joint venture") in a venture which is developing the Chernogorskoye oil field in western Siberia. On December 16, 1996, the Company executed an Acquisition Agreement to sell its Russian joint venture to Ural Petroleum Corporation ("UPC"). Closing of the transaction occurred on February 12, 1997. In accordance with the terms of the Acquisition Agreement, the Company received cash consideration of approximately $5.2 million before transaction costs, approximately $1.7 million of UPC common stock and a receivable in a form equivalent to a retained production payment of approximately $10.3 million plus interest at 10% per annum from the limited liability company formed to hold the Russian joint venture. The Company's receivable is collateralized by the partnership interest sold. The Company has the right, subject to certain conditions, to require UPC to purchase the Company's receivable from the net proceeds of an initial public offering of UPC common stock or alternatively, the Company may elect to convert all or a portion of its receivable into UPC common stock immediately prior to an initial public offering of UPC common stock. On August 23, 1995, a class action law suit was filed against the Company in Grady County, Oklahoma District Court. This suit was one of several class actions filed against Oklahoma gas producers seeking payment of royalties on amounts received in prior gas contract litigation settlements. The Oklahoma Supreme Court ruled in another case, to which the Company was not a party, that royalties were not payable on the proceeds of such settlements. Following this ruling the suit against the Company was dismissed without prejudice on September 12, 1996 upon motion filed by counsel for the plaintiff class. Accounting Matters On October 1, 1995 , the Company adopted the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which addresses the impairment of proved oil and gas properties. The SFAS No. 121 impairment test compares the expected undiscounted future net revenues from each producing field with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to "fair value" using the discounted future net revenues for the producing field. The Company recorded an additional impairment charge for proved properties under SFAS No. 121 of $1.0 million in the fourth quarter of 1995. -32- In November 1996, the Company adopted a stock option plan (the "Stock Option Plan") which covers a maximum of 700,000 shares. Options granted under the Stock Option Plan are to be exercisable at the market price of Company stock on the date of grant and have a term of ten years but may not be exercised during the initial five years. Options vest twenty-five percent on the date of grant and an additional twenty-five percent upon the completion of each of the following three years of employment with the Company. Options however will be fully vested in the event of an employment termination due to death, disability or normal retirement and options may terminate upon any termination of employment for cause. In the event of any acquisition of the Company, the options will also fully vest and upon completion of such acquisition, unexercised options will terminate. The Company adopted SFAS No. 123, "Accounting for Stock-Based Compensation," for the year ended December 31, 1996 through compliance with the disclosure requirements set forth in SFAS No. 123. Effective November 21, 1996, the Company authorized the issuance of 256,598 options, exercisable at $20.50 per share, the fair market value on the date of issuance, in connection with the termination of future awards under the Company's SAR plan. On December 31, 1996, the Company granted options to purchase 42,880 shares of the Company's common stock under the Stock Option Plan, exercisable at $24.875 per share, the fair market value on the date of issuance. Effects of Inflation and Changing Prices The Company's results of operations and cash flow are affected by changing oil and gas prices (see Note 7). Within the United States inflation has had a minimal effect on the Company. The Company cannot predict the extent of any such effect. If oil and gas prices increase, there could be a corresponding increase in the cost to the Company for drilling and related services as well as an increase in revenues. -33- ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Consolidated Financial Statements that constitute Item 8 follow the text of this report. An index to the Consolidated Financial Statements and Schedules appears in Item 14(a) of this report. ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this Item is incorporated by reference from the Company's Proxy Statement. ITEM 11. EXECUTIVE COMPENSATION The information required by this Item is incorporated by reference from the Company's Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this Item is incorporated by reference from the Company's Proxy Statement. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this Item is incorporated by reference from the Company's Proxy Statement. -34- PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) and (a)(2) Financial Statements and Financial Statement Schedules: Report of Independent Accountants............................ F-1 Consolidated Balance Sheets.................................. F-2 Consolidated Statements of Income............................ F-3 Consolidated Statements of Stockholders' Equity.............. F-4 Consolidated Statements of Cash Flows........................ F-5 Notes to Consolidated Financial Statements................... F-7 All other schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto. (b) Reports on Form 8-K. One report on Form 8-K dated December 16, 1996 was filed regarding the sale of the Company's Russian joint venture during the last quarter of the period covered by this report. (c) Exhibits. The following exhibits are filed with or incorporated into this report on Form 10-K: Exhibit Number Description - ------ ----------- 1.1* Form of Underwriting Agreement, as amended 1.2 Form of Underwriting Agreement incorporated by reference to Form S-3 (File No. 333-20587) 3.1* Restated Certificate of Incorporation of the Registrant, as amended 3.1A* Restated Certificate of Incorporation of the Registrant (as of November 17, 1992) 3.2* Restated Bylaws of the Registrant 10.3* Stock Option Plan 10.4* Stock Appreciation Rights Plan 10.5* Cash Bonus Plan 10.6* Net Profits Interest Bonus Plan 10.7* Summary Plan Description/Pension Plan dated January 1, 1985 10.8* Non-qualified Unfunded Supplemental Retirement Plan, as amended 10.9* Non-qualified Supplemental Trust Agreement, as amended 10.10* Summary Plan Description Custom 401(k) Plan and Trust 10.11* Stock Option Agreement - Mark A. Hellerstein 10.12* Stock Option Agreement - Ronald D. Boone 10.13* Employment Agreement between Registrant and Mark A. Hellerstein 10.34** Summary Plan Description 401(k) Profit Sharing Plan 10.35** Summary Plan Description/Pension Plan dated December 30, 1994 10.41 Second Restated Partnership Agreement - Panterra Petroleum 10.42 Purchase and Sale Agreement between Siete Oil & Gas Corporation and Registrant incorporated by reference from Exhibit 10.42 filed on Form 8-K dated June 28, 1996, as amended by a Form 8-K/A dated June 28, 1996 -35- 10.43 Acquisition Agreement regarding the sale of the Company's Russian joint venture incorporated by reference from the Exhibit 10.43 filed on Form 8-K dated December 16, 1996 10.44 Amended and Restated Credit Agreement between Registrant and NationsBank of Texas, N.A. and Norwest Bank Colorado, National Association, dated April 1, 1996, incorporated by reference from Exhibit 10.1 filed on Form 8-K dated January 28, 1997 10.45 Amended and Restated Credit Agreement between Panterra Petroleum, Registrant and First Interstate Bank, dated February 6, 1995, incorporated by reference from Exhibit 10.2 filed on Form 8-K dated January 28, 1997 10.46 Employment Agreement between Registrant and Ralph H. Smith, effective October 1, 1995, incorporated by reference from Exhibit 99 filed on Form 8-K dated January 28, 1997 10.47 Stock Option Plan 10.48 Incentive Stock Option Plan 21.1* Subsidiaries of Registrant 23.2 Consent of Coopers & Lybrand L.L.P. 24.1* Power of Attorney (included on signature page) 27.1 Financial Data Schedule * Incorporated by reference from Registrant's Registration Statement on Form S-1 (File No. 33-53512) ** Incorporated by reference from Registrant's Annual Report on Form 10-K for the years ended December 31, 1992 through 1995 (File No. 0-20872) (d) Financial Statement Schedules. See Item 14(a) above. -36- REPORT OF INDEPENDENT ACCOUNTANTS Board of Directors and Stockholders St. Mary Land & Exploration Company and Subsidiaries: We have audited the accompanying consolidated balance sheets of St. Mary Land & Exploration Company and Subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, 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 consolidated financial position of St. Mary Land & Exploration Company and Subsidiaries as of December 31, 1996 and 1995, and the consolidated 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 discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for impairment of long-lived assets in 1995. COOPERS & LYBRAND L.L.P. Denver, Colorado March 3, 1997, except for the second paragraph of Note 14, as to which the date is March 21, 1997. F-1 ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY DATA ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, except share amounts)
ASSETS December 31, -------------------------- 1996 1995 ---------- ---------- Current assets: Cash and cash equivalents $ 3,338 $ 1,723 Accounts receivable 21,443 8,068 Prepaid expenses 1,115 850 Refundable income taxes 57 176 Investment in Russian joint venture held for sale 6,151 - ---------- ---------- Total current assets 32,104 10,817 ---------- ---------- Property and equipment (successful efforts method), at cost: Proved oil and gas properties 198,652 165,750 Unproved oil and gas properties, net of impairment allowance of $2,330 in 1996 and $2,971 in 1995 14,581 11,752 Other 3,509 2,535 ---------- ---------- 216,742 180,037 Less accumulated depletion, depreciation, (115,232) (108,392) amortization and impairment ---------- ---------- 101,510 71,645 ---------- ---------- Other assets: Investment in Russian joint venture - 4,140 Investment in Summo Minerals Corporation 4,884 4,842 Restricted cash 2,918 - Other assets 2,855 4,682 ---------- ---------- 10,657 13,664 ---------- ---------- $ 144,271 $ 96,126 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued expenses $ 16,628 $ 7,715 Stock appreciation rights 1,550 - ---------- ---------- Total current liabilities 18,178 7,715 ---------- ---------- Long-term liabilities: Long-term debt 43,589 19,602 Deferred income taxes 5,790 1,228 Stock appreciation rights 1,195 1,178 Other noncurrent liabilities 359 121 ---------- ---------- 50,933 22,129 ---------- ---------- Commitments and contingencies (Notes 1, 7, 8 and 9) Stockholders' equity: Common stock, $.01 par value: authorized - 15,000,000 shares; issued and outstanding - 8,759,214 shares in 1996 and 8,761,855 shares in 1995 88 88 Additional paid-in capital 15,801 15,835 Retained earnings 59,303 50,378 Unrealized gain (loss) on marketable equity securities-available for sale (32) 15 Treasury stock - 2,572 shares, at cost - (34) ---------- ---------- Total stockholders' equity 75,160 66,282 ---------- ---------- $ 144,271 $ 96,126 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. F-2 ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In thousands, except per share amounts)
For the Years Ended December 31, --------------------------------- 1996 1995 1994 --------- --------- --------- Operating revenues: Oil and gas production $ 56,774 $ 36,569 $ 38,239 Gain on sale of proved properties 2,254 1,292 418 Gas contract settlements and other revenues 523 789 6,128 --------- --------- -------- Total operating revenues 59,551 38,650 44,785 --------- --------- --------- Operating expenses: Oil and gas production 12,897 10,646 10,496 Depletion, depreciation and amortization 12,732 10,227 10,134 Impairment of proved properties 408 2,676 4,219 Exploration 8,185 5,073 8,104 Abandonment and impairment of unproved properties 1,469 2,359 1,023 General and administrative 7,603 5,328 5,261 Gas contract disputes and other 78 152 493 (Income) loss in equity investees (1,272) 579 348 --------- --------- --------- Total operating expenses 42,100 37,040 40,078 --------- --------- --------- Income from operations 17,451 1,610 4,707 Nonoperating income and (expense): Interest income 186 287 426 Interest expense (2,137) (1,183) (951) --------- --------- --------- Income from continuing operations before income taxes 15,500 714 4,182 Income tax expense (benefit) 5,333 (723) 445 --------- --------- --------- Income from continuing operations 10,167 1,437 3,737 Gain on sale of discontinued operations, net of taxes of $82 in 1996 and $158 in 1995 159 306 - --------- --------- --------- Net income $ 10,326 $ 1,743 $ 3,737 ========= ========= ========= Net income per common share: Income from continuing operations $ 1.16 $ .17 $ .43 Gain on sale of discontinued operations .02 .03 - --------- --------- --------- Net income per share $ 1.18 $ .20 $ .43 ========= ========= ========= Weighted average common shares outstanding 8,759 8,760 8,763 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. F-3 ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (In thousands, except share amounts)
Unrealized Gain (Loss) On Marketable Equity Common Stock Additional Securities -------------------------- Paid-in Retained Available Shares Amount Capital Earnings For Sale ----------- ---------- ---------- ---------- ---------- Balance, December 31, 1993 8,762,604 $ 88 $ 15,845 $ 47,702 $ - Net income - - - 3,737 - Cash dividends, $ .16 per share - - - (1,402) - Adoption of SFAS No. 115 - - - - 589 Unrealized loss - - - - (525) ----------- ---------- ---------- ---------- ---------- Balance, December 31, 1994 8,762,604 88 15,845 50,037 64 Net income - - - 1,743 - Cash dividends, $ .16 per share - - - (1,402) - Unrealized loss - - - - (49) Purchase and retirement of common stock (749) - (10) - - ----------- ---------- ---------- ---------- ---------- Balance, December 31, 1995 8,761,855 88 15,835 50,378 15 Net income - - - 10,326 - Cash dividends, $ .16 per share - - - (1,401) - Unrealized loss - - - - (47) Purchase and retirement of common stock (69) - - - - Retirement of treasury stock (2,572) - (34) - - ----------- ---------- ---------- ---------- ---------- Balance, December 31, 1996 8,759,214 $ 88 $ 15,801 $ 59,303 $ (32) =========== ========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. F-4 ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
For the Years Ended December 31, --------------------------------- 1996 1995 1994 --------- --------- --------- Cash flows from operating activities: Cash received from oil and gas operations $ 44,643 $ 33,663 $ 41,346 Cash paid for oil and gas operations, including general and administrative expenses (13,387) (13,051) (13,175) Exploration expenses (4,843) (3,672) (6,860) Interest and other receipts 50 1,356 686 Interest paid (1,953) (795) (767) Income taxes refunded (paid) (305) 212 (959) --------- --------- --------- Net cash provided by operating activities 24,205 17,713 20,271 --------- --------- --------- Cash flows from investing activities: Proceeds from sale of oil and gas properties 3,082 2,337 221 Capital expenditures, including dry hole costs (27,504) (22,657) (16,950) Acquisition of oil and gas properties (20,957) (8,111) (5,066) Purchase of interest in St. Mary Operating Company 3,059 - - Investment in Russian joint venture (209) (297) (631) Investment in Summo Minerals Corporation - (4,528) (219) Restricted cash (2,918) - - Other 272 264 (499) --------- --------- --------- Net cash used by investing activitie (45,175) (32,992) (23,144) --------- --------- --------- Cash flows from financing activities: Proceeds from long-term debt 42,996 19,513 - Repayment of long-term debt (19,009) (11,041) (578) Dividends paid (1,401) (1,402) (1,402) Other (1) (44) - --------- --------- --------- Net cash provided (used) by financing activities 22,585 7,026 (1,980) --------- --------- --------- Net increase (decrease) in cash and cash equivalents 1,615 (8,253) (4,853) Cash and cash equivalents at beginning of period 1,723 9,976 14,829 --------- --------- --------- Cash and cash equivalents at end of period $ 3,338 $ 1,723 $ 9,976 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. F-5 ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) (In thousands)
For the Years Ended December 31, -------------------------------------- 1996 1995 1994 ---------- ---------- ---------- Reconciliation of net income to net cash provided by operating activities: Net income $ 10,326 $ 1,743 $ 3,737 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 12,732 10,227 10,134 Impairment of proved properties 408 2,676 4,219 (Income) loss in equity investees (1,272) 579 348 Gain on sale of proved properties (2,254) (1,292) (418) Dry hole costs 3,048 1,286 2,435 Abandonment and impairment of unproved properties 1,469 2,359 1,023 Deferred income taxes 4,634 (1,038) (835) Other 17 (407) 105 ---------- ---------- ---------- 29,108 16,133 20,748 Changes in assets and liabilities, net of effect of purchase of interest in St. Mary Operating Company: Accounts receivable (9,288) 166 (450) Refundable income taxes 119 200 448 Accounts payable and accrued expenses 4,338 706 (402) Deferred income taxes (72) 508 (73) ---------- ---------- ---------- Net cash provided by operating activities $ 24,205 $ 17,713 $ 20,271 ========== ========== ========== Supplemental schedule of noncash investing and financing activities: In January 1994, the Company acquired an additional 10.28% general partnership interest in Panterra Petroleum for approximatley $1.3 million in cash and the assumption of $1.9 million in bank debt. In December 1994, the Company acquired an additional 14.9% general partnership interest in Panterra Petroleum by participating in the buyout of Wesco Resources, another general partner. This interest was acquired for $3.3 million and the assumption of $2.2 million in bank debt. In May 1995, the Company sold a portion of its remaining real estate assets for $975,000 and carried back a note from the buyer for $731,000. In March 1996, the Company acquired the remaining 35% shareholder interest in St. Mary Operating Company for $234,000 and assumed net liabilities of $339,000, resulting in acquired cash of $3.1 million.
The accompanying notes are an integral part of these consolidated financial statements. F-6 ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies: Description of Operations: St. Mary Land & Exploration Company (the "Company") is an independent energy company engaged in the exploration, development, acquisition and production of crude oil and natural gas in the United States, Russia, Canada and Trinidad and Tobago. The Company's operations are focused in five core operating areas in the United States: the Mid-Continent region; the ArkLaTex region; south Louisiana; the Williston Basin; and the Permian Basin. During 1996, the Company agreed to, and in February 1997, completed the sale of its interest in the Russian joint venture. Reclassifications: Certain amounts in the 1995 and 1994 consolidated financial statements have been reclassified to correspond to the 1996 presentation. Basis of Presentation: The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. All significant intercompany accounts and transactions have been eliminated. The Company accounts for its investment in the Russian joint venture and Summo Minerals Corporation under the equity method of accounting. In March 1996, the Company completed its purchase of the remaining stock of St. Mary Operating Company ("SMOC"). The purchase increased the Company's ownership in SMOC from 65% to 100%. Through March 31, 1996, the Company accounted for its investment in SMOC using the equity method of accounting. The Company's interests in other oil and gas ventures and partnerships are proportionately consolidated, including its investment in Panterra Petroleum ("Panterra"). Cash and Cash Equivalents: The Company considers all highly liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because the instruments have maturity dates of three months or less. Concentration of Credit Risk: Substantially all of the Company's receivables are within the oil and gas industry, primarily from purchasers of oil and gas and joint venture participants. Although diversified within many companies, collectibility is dependent upon the general economic conditions of the industry. The receivables are not collateralized and to date, the Company has had minimal bad debts. F-7 The Company has accounts with separate banks in Denver, Colorado, Dallas, Texas and Shreveport, Louisiana. At December 31, 1996 and 1995, the Company had $1,864,000 and $386,000, respectively, invested in money market funds consisting of corporate commercial paper, repurchase agreements and U.S. Treasury obligations. The Company's policy is to invest in conservative, highly rated instruments and to limit the amount of credit exposure to any one institution. Oil and Gas Producing Activities: The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered to be not realizable. Depletion, depreciation and amortization ("DD&A") of capitalized costs of proved oil and gas properties is provided on a property-by-property basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds from equipment salvage. The estimated restoration, dismantlement and abandonment costs are expected to be offset by the estimated residual value of lease and well equipment. In March 1995, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which addresses the impairment of proved oil and gas properties. The Company adopted SFAS No. 121 as of October 1, 1995 and recorded an additional impairment charge for proved properties of $1,003,000 in the fourth quarter of 1995. During 1996 the Company recorded impairment charges for proved properties of $408,000. The SFAS No. 121 impairment test compares the expected undiscounted future net revenues on a property-by-property basis with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to "fair value," which is determined using discounted future net revenues from the producing property. Prior to the adoption of SFAS No. 121, the net capitalized costs of proved oil and gas properties were limited to the aggregate undiscounted, after-tax, future net revenues determined on a property-by-property basis (the "ceiling test"). If the net capitalized costs exceeded the ceiling, the excess was recorded as a charge to operations. The Company recorded impairment charges for proved properties under this ceiling test method of $1,673,000 and $4,219,000 in 1995 and 1994 respectively, due to price declines and downward reserve revisions. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as recoveries of costs. F-8 Other Property and Equipment: Other property and equipment is recorded at cost. Costs of renewal and improvement which substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed when incurred. Depreciation and amortization is provided using the straight-line method over the estimated useful lives of the assets from 3 to 15 years. Gains and losses on dispositions are included in operations. Restricted Cash: Proceeds from the sales of certain oil and gas producing properties are held in escrow and restricted for future acquisitions under a tax-free exchange agreement. These funds have been invested in money market funds consisting of corporate commercial paper, repurchase agreements and U.S. Treasury obligations and are carried at cost which approximates market. Gas Balancing: The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. The Company records revenue for its share of gas sold by other owners which cannot be balanced in the future due to insufficient remaining reserves. The related receivable totaling $850,000 and $868,000 at December 31, 1996 and 1995, respectively, is included in other assets in the accompanying balance sheets. The Company's remaining underproduced gas balancing position is included in the Company's proved oil and gas reserves (see Note 13). Financial Instruments: The Company periodically uses commodity contracts to hedge or otherwise reduce the impact of oil and gas price fluctuations. Gains and losses on commodity hedge contracts are deferred until recognized as an adjustment to revenues when the related oil and gas is sold. Cash flows from such transactions are included in oil and gas operations. The Company realized net losses of $4,253,000, $11,000 and $16,000 on these contracts for the years ended December 31, 1996, 1995 and 1994 respectively. In connection with these hedging transactions, the Company may be exposed to nonperformance by other parties to such agreements, thereby subjecting the Company to current oil and gas prices or interest rates. However, the Company only enters into hedging contracts with large financial institutions and does not anticipate nonperformance. As of December 31, 1995, the Company adopted SFAS No. 107, "Disclosures about Fair Value of Financial Instruments," requiring disclosure of fair value information of financial instruments, whether or not recognized in the balance sheet, for which it is practicable to estimate fair value. In cases where quoted market prices are not available, fair values are based on estimates using present value or other valuation techniques. Disclosures about fair value are not required for certain financial instruments and all nonfinancial instruments. F-9 Income Taxes: Deferred income taxes are provided on the difference between the tax basis of an asset or liability and its reported amount in the financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Net Income Per Share: Net income per share of common stock is calculated by dividing net income by the weighted average of common shares and common equivalent shares, if dilutive, outstanding during each year. Common equivalent shares were not materially dilutive for any periods presented. In March 1997, the FASB issued SFAS No. 128, "Earnings Per Share," which requires a dual presentation of basic and diluted earnings per share. The Company plans to adopt SFAS No. 128 in 1997. Management believes the adoption of this standard will not have a material impact on earnings per share of the Company. Use of Estimates in the Preparation of Financial Statements: 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. 2. Accounts Receivable: Accounts receivable are composed of the following: December 31, ------------------------ 1996 1995 -------- -------- (in thousands) Accrued oil and gas sales: Due from third parties $ 14,309 $ 4,827 Due from St. Mary Operating Company - 1,958 Due from joint interest owners 7,134 1,283 -------- -------- $ 21,443 $ 8,068 ======== ======== 3. Investment in Summo Minerals Corporation: As of December 31, 1996 and 1995, the Company owned 9,644,093 (49% of total shares outstanding) and 9,028,003 (51% of total shares outstanding) shares of Summo Minerals Corporation ("Summo"), an international mining company, with a total cost of $5,608,000 and $5,108,000, and warrants to acquire an additional 6,261,000 and 5,495,000 shares, respectively. Exercise prices for the warrants range from $.80 to $1.01, using the Canadian exchange rate in effect on December 31, 1996 ($.73). Summo completed its initial public offering effective October 31, 1994 at $.44 per share. The market value of this investment was $8,444,000 at December 31, 1996 and $7,945,000 at December 31, 1995. For the years ending December 31, 1996 and 1995, the Company reported equity in losses from Summo of $457,000 and $257,000, respectively. F-10 4. Income Taxes: The provision for income taxes consists of the following: For the Years Ended December 31, -------------------------------- 1996 1995 1994 -------- -------- -------- (In thousands) Current taxes: Federal $ 81 $ 77 $ 835 State 700 396 445 Deferred taxes 4,634 (1,038) (835) -------- -------- -------- Total income tax expense (benefit) $ 5,415 $ (565) $ 445 ======== ======== ======== Continuing operations $ 5,333 $ (723) $ 445 Discontinued operations 82 158 - -------- -------- -------- Total income tax expense (benefit) $ 5,415 $ (565) $ 445 ======== ======== ======== The above taxes from continuing operations are net of alternative fuel credits (Section 29) of $551,000 in 1996, $624,000 in 1995 and $1,333,000 in 1994. The components of the net deferred tax liability are as follows (in thousands): December 31, -------------------- 1996 1995 -------- -------- Deferred tax assets Non-current Other, primarily employee benefits $(2,152) $(1,458) State tax net operating loss carryforward (1,600) (1,402) Alternative minimum tax credit carryforward (691) (565) -------- -------- Total deferred tax assets (4,443) (3,425) Valuation allowance 898 1,402 -------- -------- Net deferred tax assets (3,545) (2,023) Deferred tax liabilities Non-current Oil and gas properties 8,787 2,886 Other 548 365 -------- -------- Net deferred tax liability $ 5,790 $ 1,228 ======== ======== F-11 At December 31, 1996, the Company had state net operating loss carryforwards of approximately $26.8 million which expire between 1997 and 2011 and alternative minimum tax credit carryforwards of $691,000 which may be carried forward indefinitely. The Company's valuation allowance relates to its state net operating loss carryforwards since the Company anticipates that a portion of the carryovers from prior years will expire before they can be utilized. The net change in valuation allowance in 1996 results from utilization of Oklahoma net operating loss carryforwards and the current year calculation of deferred state income tax for Oklahoma. The net change in valuation allowance in 1995 is primarily a result of the recognition of a capital loss carryover. The net change in valuation allowance in 1994 is primarily a result of state net operating loss carryforwards and Federal capital loss carryforwards expected to expire before they can be utilized. Federal income tax expense (benefit) differs from the amount that would be provided by applying the statutory U.S. Federal income tax rate to income before income taxes for the following reasons: For the Years Ended December 31, -------------------------------- 1996 1995 1994 -------- -------- -------- (In thousands) Federal statutory taxes $5,270 $ 242 $1,422 Increase (reduction) in taxes resulting from: State taxes (net of Federal benefit) 1,212 261 294 Statutory depletion (173) (173) (174) Alternative fuel credits (Section 29) (551) (624) (1,333) Change in valuation allowance (504) (412) 225 Other 79 (17) 11 -------- -------- -------- Income tax expense (benefit) $ 5,333 $ (723) $ 445 ======== ======== ======== 5. Long-term Debt and Notes Payable: In April 1996, the Company amended and restated its long-term revolving credit facility dated March 1, 1993 and extended its maturity to June 30, 1999. Borrowings under this agreement are limited to the lesser of $60,000,000 or the current borrowing base, as determined by the bank annually. The borrowing base at December 31, 1996 was $40,000,000 and was increased to $60,000,000 in February 1997 based on year-end reserve values. The agreement has a three year term, at the end of which borrowings can be converted to a five year amortizing loan. The Company can elect to allocate up to 50% of available borrowings to a short term tranche due in 364 days. Borrowings under this agreement are collateralized by a mortgage of substantially all of the Company's producing oil and gas properties. In addition, the Company must comply with certain other covenants, including maintenance of stockholders' equity at a specified level, limitations on additional indebtedness and payment of dividends. As of December 31, 1996 and 1995, $33,875,000 and $8,300,000, respectively, was outstanding under this credit facility. F-12 Through March 31, 1995, interest on borrowings was computed at the bank's prime rate or LIBOR plus 1.5%. Effective April 1, 1995, interest on borrowings, based on debt to capitalization ratios, and commitment fees on the unused portion of borrowings are calculated as follows: Debt to Capitalization Ratio Revolving Loan Term Loan ---------------------------- -------------- --------- Interest rates: Less than 30% Prime rate or Prime rate or LIBOR +.5% LIBOR +.75% Greater than 30%, less than 40% Prime rate or Prime rate or LIBOR +.75% LIBOR +1.0% Greater than 40%, less than 50% Prime rate or Prime rate or LIBOR + 1.0% LIBOR +1.25% Greater than 50% Prime rate +.125% Prime rate +.125% or LIBOR +1.25% or LIBOR +1.5% Commitment Fees on Unused Portion Short Term Tranche Long Term Tranche --------------------------------- ------------------ ----------------- Less than 50% of .125% .25% available borrowing Greater than 50% of .375% .50% available borrowings At December 31, 1996 and 1995, the Company's debt to capitalization ratio as defined was 37.5% and 24%, respectively. At December 31, 1996, interest on borrowings is computed at the bank's prime rate or LIBOR plus .75% (8.25% or 6.31%, respectively). At December 31, 1995, interest on borrowings was computed at the bank's prime rate or LIBOR plus .5% (8.5% or 6.16%, respectively). In February 1995, Panterra entered into a credit agreement with a bank replacing a previous credit agreement due April 30, 1998. The new credit agreement as modified on February 21, 1997 includes a two year revolving period converting to a five year amortizing loan on March 31, 1999. Borrowings under this agreement are limited to the lesser of $40,000,000 or the current borrowing base, as determined by the bank semiannually. The borrowing base at December 31, 1996 and 1995 was $26,000,000 and $18,500,000, respectively. During the revolving period, interest on borrowings, based on debt to partners' capital ratios, and commitment fees on the unused portion of the borrowings are calculated as follows: Debt to Partners' Capital Ratio Interest rates Commitment Fees ------------------------------- -------------- --------------- Less than 50% Prime rate or .25% LIBOR +1.0% Greater than 50%, less than 100% Prime rate or .25% LIBOR +1.25% Greater than 100%, less than 150% Prime rate + .125% .375% or LIBOR + 1.5% Greater than 150% Prime rate +.25% .50% or LIBOR +1.75% At December 31, 1996, Panterra's debt to partners' capital ratio as defined was 76% and interest on borrowings is computed at the bank's prime rate or LIBOR plus 1.25% (8.25% or 7.05%, respectively). Interest on borrowings at December 31, 1995 was payable at the bank's prime rate or LIBOR plus 1.5% (8.5% or 7.16%, respectively). During the amortization period, interest is payable at the bank's prime rate plus .25% or LIBOR plus 1.75%. Principal payments during the revolving period are not required if the loan amount is less than the current borrowing base. During the amortization period, monthly principal payments are payable at rates decreasing from 2.0% to 1.4% of the outstanding balance through March 2004 at which time the remaining principal balance is due. F-13 The new Panterra credit agreement is collateralized by all of Panterra's oil and gas properties and contains covenants which, among other things, restrict the acquisition of assets and the incurrence of additional debt and require that certain minimum financial ratios be maintained. As of December 31, 1996 and 1995, $13,100,000 and $15,150,000, respectively, was outstanding under this credit facility. The Company's proportionate share of the liability under Panterra's bank note payable is 74%. The carrying value of long-term debt approximates fair value because the debt is variable rate and reprices in the short term. The Company's liability for estimated annual principal payments for the next five years under both notes payable are as follows: Year Ending December 31, (In thousands) ------------ -------------- 1997 $ - 1998 - 1999 5,165 2000 8,339 2001 7,920 Thereafter 22,165 ------- $43,589 ======= 6. Gas Contract Settlements: During 1994, the Company settled the final two gas contract disputes with pipeline companies, recognizing income of $5,741,000. 7. Commitments and Contingencies: The Company leases office space under operating leases which were amended and extended through May 31, 2002. The annual minimum lease payments approximate $523,000. The Company has noncancelable annual leases with affiliates of approximately $75,000. Rent expense, net of sublease income, was $426,000, $131,000 and $166,000 in 1996, 1995 and 1994, respectively. F-14 The Company has the following commodity contracts in place as of December 31, 1996 to hedge or otherwise reduce the impact of oil and gas price fluctuations: Product Volumes/month Fixed Price Duration ----------- ------------- ----------- ------------ Natural Gas 15,000 MMBTU $2.065 1/97 - 3/97 Natural Gas 107,000 MMBTU $2.305 1/97 - 3/97 Natural Gas 200,000 MMBTU $2.665 1/97 - 3/97 Natural Gas 24,000 MMBTU $1.87 1/97 - 5/97 Natural Gas 35,000 MMBTU $1.73 1/97 - 10/97 Natural Gas 39,000 MMBTU $2.015 1/97 - 10/97 Natural Gas 24,000 MMBTU $1.825 1/97 - 12/97 Natural Gas 15,000 MMBTU $1.94 1/97 - 2/98 Natural Gas 22,500 MMBTU $1.9025 1/97 - 6/98 Oil 10,000 BBLS $18.40 1/97 Oil 12,100 BBLS $18.36 1/97 Oil 5,000 BBLS $18.30 1/97 Oil 3,200 BBLS $17.95 1/97 - 2/97 Oil 1,200 BBLS $18.44 1/97 - 2/97 Oil 1,000 BBLS $16.95 1/97 - 4/97 Oil 1,125 BBLS $16.98 1/97 - 10/97 Oil 1,000 BBLS $21.35 2/97 - 12/97 Oil 1,300 BBLS $21.05 2/97 - 1/98 Oil 10,000 BBLS $17.95 2/97 - 6/98 The fair value of the Company's commodity hedging contracts based on year end futures pricing would require the Company to pay approximately $2,585,000, if these contracts were terminated on December 31, 1996. At December 31, 1996, Panterra held various hedge contracts covering 280,000 BBLS of future production. These contracts expire at various dates through May 1997, with floor prices ranging from $18.00 / BBL to $27.00 / BBL. If the open hedging contracts were liquidated at December 31, 1996, the Company would recognize a loss of approximately $211,000. On August 23, 1995, a class action law suit was filed against the Company in Grady County, Oklahoma District Court. This suit was one of several class actions filed against Oklahoma gas producers seeking payment of royalties on amounts received in prior gas contract litigation settlements. Following the issuance of a decision by the Oklahoma Supreme Court in another case, to which the Company was not a party, holding that royalties were not payable on the proceeds of such settlements, this suit was dismissed without prejudice on September 12, 1996 upon motion filed by counsel for the plaintiff class. 8. Compensation Plans: In January 1992, the Company adopted two compensation plans for key employees. A cash bonus plan not to exceed 50% of the participants' aggregate base salaries was adopted and any awards will be based on performance adjusted salaries. A net profits interest bonus plan allows participants to receive an aggregate 10% net profits interest after the Company has recovered 100% of its investment in various pools of oil and gas wells completed or acquired during the year. This interest is increased to 20% after the Company recovers 200%. The Company records compensation expense once it recovers its investment, and net profits attributable to the properties are payable to the employees. During 1996, the Company recorded compensation expense of $119,000 relating to net profits attributable to these properties. F-15 In March 1992, the Company adopted a stock appreciation rights ("SAR") plan for officers and directors and awarded 90,962 shares with a value of $4.26 per share effective January 1, 1992. This SAR vests over a four-year period, with payment occurring five years after the date of grant. The SAR plan replaced the restricted stock bonus plan. In 1996 the Company awarded 61,873 shares with a value of $14.00 per share effective January 1, 1996. In 1995 the Company awarded 34,917 shares with a value of $13.25 per share effective January 1, 1995. In 1994 the Company awarded 38,938 shares with a value of $11.63 per share effective January 1, 1994 and in 1993 the Company awarded 35,684 shares with a value of $11.50 per share effective January 1, 1993. Compensation expense recognized under the SAR plan was $1,567,000, $220,247 and $268,286 in 1996, 1995 and 1994, respectively. In November 1996, the Company terminated future awards under the Company's SAR plan and capped the value of the shares under the SAR plan at the then fair market value of the Company's common stock of $20.50 per share, in connection with the adoption of a new stock option plan. The resulting liability of $2,745,000 is classified as current and long-term in the consolidated balance sheets, based on expected payment dates. Through September 1992, the Company had a restricted stock bonus plan ("Plan") covering officers and key employees. The Plan provided for the granting of stock and cash not to exceed 100% of the participant's then annual salary. The Plan provided that any portion or all of the stock could be purchased by the Company in the case of termination of employment for any reason. A participant has the option at any time to sell shares acquired under the Plan to the Company at a price related to its fair market value as defined in the Plan. At December 31, 1996, there were 33,520 shares issued and outstanding under the Plan. The Company's stock price was $24.875 at December 31, 1996. The Company has a defined contribution pension plan ("401(k) Plan") qualified under the Employee Retirement Income Security Act of 1974. This 401(k) Plan allows eligible employees to contribute up to 9% of their income. The Company matches each employee's contributions up to 6% of the employee's income and also may make additional contributions at its discretion. Contributions to the 401(k) Plan amounted to $199,000, $183,000 and $93,000 for the years ended December 31, 1996, 1995 and 1994, respectively. During 1996 the Company established the St. Mary Land & Exploration Company Stock Option Plan (the "Stock Option Plan"). The Stock Option Plan grants options to purchase shares of the Company's common stock to eligible employees, contractors, and current and former members of the Board of Directors. The Company has reserved 700,000 shares of its own common stock for issuance under the Stock Option Plan. During 1996 options to purchase 256,598, in connection with the termination of future awards under the Company's SAR plan, and 42,880 shares of the Company's common stock were granted under the Stock Option Plan at exercise prices of $20.50 and $24.875, respectively, which were equal to the respective market prices of the stock on the grant dates. The vesting periods of these options vary from 0 to 3 years, and the options are exercisable for the period from five to ten years after the date of grant. No options were exercised during the year ended December 31, 1996. Also, in 1990 and 1991, the Company granted certain officers options to acquire 54,614 shares of common stock at an exercise price of $3.30 per share. The options are now fully vested and expire ten years from the date of grant. F-16 A summary of the status of the Company's Stock Option Plan including the 1990 and 1991 options as of December 31, 1996, and changes during the year then ended is as follows: Weighted Average Shares Exercise Price ------- -------------- Outstanding at beginning of year 54,614 $ 3.30 Granted 299,478 21.13 Exercised - - Forfeited - - ------- ------- Outstanding at end of year 354,092 $ 18.38 ======= ======= Options exercisable at year end 145,576 ======= Options available for future grant 400,522 ======= Weighted average fair value of options granted during the year $ 8.06 ======= In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation." This Statement establishes a fair value method of accounting for stock-based compensation plans either through recognition or disclosure. The Company has elected to continue following Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25) and has elected to adopt SFAS No. 123 through compliance with the disclosure requirements set forth in the Statement. Because the exercise price of the Company's employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized under APB No. 25. Pro forma information regarding net income and earnings per share is required by SFAS No. 123 and has been determined as if the Company had accounted for its employee stock options under the fair value method of that Statement. The fair value of these options was estimated at the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions for 1996: risk-free interest rate(s) of 6.2%; dividend yield of .76%; volatility factor of the expected market price of the Company's common stock of 37.88%; and weighted-average expected life of the options of 4.8 years. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is management's opinion that the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. F-17 For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. Had compensation cost been determined based on the fair value at grant dates for stock options awards consistent with SFAS No. 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below: Pro Forma for the Year Ended December 31, 1996 ----------------------- (in thousands, except per share amounts) Net Income applicable to As reported $ 10,326 common stock Pro forma $ 9,607 Primary earnings per share As reported $ 1.18 Pro forma $ 1.10 The effects of applying SFAS No. 123 in the pro forma disclosure are not necessarily indicative of actual future amounts, and SFAS No. 123 does not apply to awards granted prior to 1995. Additional awards in future years are anticipated. 9. Pension Plans: The Company's employees participate in a noncontributory pension plan covering substantially all employees who meet age and service requirements (the "Primary Plan"). Benefits provided under this pension plan are based primarily on each employee's career earnings. As of December 31, 1996, plan assets were invested primarily in diversified stock and bond funds. In addition, the Company has a supplemental noncontributory pension plan covering certain management employees (the "Supplemental Plan"). Benefits are based mainly on each participant's years of service, final average compensation and estimated benefits received from certain other plans. The components of net pension expense are as follows: For the Years Ended December 31, -------------------------- 1996 1995 1994 ------ ------ ------ (In thousands) Service cost - benefits earned during the year $ 131 $ 79 $ 129 Interest cost on projected benefit obligations 80 51 45 Actual (return) loss on plan assets (67) (133) 27 Net amortization (deferral) 6 61 (94) ------ ------ ------ Net pension expense $ 150 $ 58 $ 107 ====== ====== ====== F-18 A reconciliation of the funded status of the plans to accrued pension liability is as follows:
Primary Plan Supplemental Plan December 31, December 31, ----------------- ----------------- 1996 1995 1996 1995 ------ ------ ------ ------ (In thousands) Actuarial present value of benefits based on service date and present pay levels: Vested $ 497 $ 263 $ 202 $ 140 Nonvested 154 63 23 - ------ ------ ------ ------ Accumulated benefit obligation 651 326 225 140 Additional amounts related to pay increases 281 219 172 127 ------ ------ ------ ------ Projected benefit obligation 932 545 398 267 Plan assets at fair value 874 810 - - ------ ------ ------ ------ Projected benefit obligation (in excess of) or less than plan assets (58) 265 (398) (267) Unrecognized (gain) loss - (261) 224 192 Unrecognized net asset (7) (17) - - ------ ------ ------ ------ Accrued pension liability included in the consolidated balance sheets $ (65) $ (13) $(174) $ (75) ====== ====== ====== ======
Actuarial assumptions for December 31, 1996 and 1995 are as follows: 1996 1995 ---- ---- Discount rate 7.50% 7.50% Average salary growth rate 5.00% 5.00% Return on plan assets 8.00% 8.00% 10. Related Party Transactions: Through October 1994, a majority of the Company's oil and gas operations, other than Louisiana royalties, including acquisition of unproved properties, were administered by SMOC. Operations were conducted under a domestic agreement with SMOC and various individuals (the "Anderman Group") which was effective January 1, 1992, amended July 1, 1993 and terminated on December 31, 1995. Through the termination date the Company paid 70% of all costs for lease acquisitions, geophysical surveys, drilling and production and owned 68% of all resulting properties, production and reserves. Through December 31, 1995, the Company also paid 65% of all overhead costs of SMOC incurred for exploration and production activities, and through September 1995, quarterly fees of $125,000 to the Anderman Group. Effective April 1, 1995, the Company gave notice that it would not participate in any new international ventures managed by the Anderman Group, and on November 30, 1995, withdrew from all international partnerships with the exception of those with interests in Russia, Canada and Trinidad and Tobago. During 1995, the Company recorded a charge to operations of $252,000 resulting from its withdrawal from the international partnerships. F-19 Billings from SMOC, which represent charges for lease operating, exploration, development and general and administrative expenses, amounted to $11,451,000 and $14,008,000 for the years ended December 31, 1995 and 1994, respectively. As of December 31, 1995, accounts payable included $746,000 owed to SMOC. 11. Investment in Russian Joint Venture: In September 1991, the Company, through an affiliate of the Anderman Group, acquired a 22% interest in The Limited Liability Company Chernogorskoye (the "Russian joint venture"). The Company's interest in the Russian joint venture was reduced to 18% in 1993. The Russian joint venture is developing the Chernogorskoye field in western Siberia. On December 16, 1996, the Company executed an Acquisition Agreement to sell its interest in the Russian joint venture to Ural Petroleum Corporation ("UPC"). Closing of the transaction occurred on February 12, 1997. In accordance with the terms of the Acquisition Agreement, the Company received cash consideration of approximately $5.2 million before transaction costs, approximately $1.7 million of UPC common stock and a receivable in a form equivalent to a retained production payment of approximately $10.3 million plus interest at 10% per annum from the limited liability company formed to hold the Russian joint venture interest. The Company's receivable is collateralized by the partnership interest sold. The Company has the right, subject to certain conditions, to require UPC to purchase the Company's receivable from the net proceeds of an initial public offering of UPC common stock or alternatively, the Company may elect to convert all or a portion of its receivable into UPC common stock immediately prior to an initial public offering of UPC common stock. As of December 31, 1996 the Company's investment in the Russian joint venture is classified in the financial statements as held for sale. Summarized financial information of the Russian joint venture is shown below: For the Years Ended December 31, --------------------------------- 1996 1995 1994 --------- --------- --------- (Unaudited, in thousands) Income Statement: Oil and gas revenues $ 60,367 $ 29,479 $ 15,035 Operating expenses 44,752 22,547 12,707 Interest and other expenses 9,199 8,966 5,831 --------- --------- --------- Net income (loss) $ 6,416 $ (2,034) $ (3,503) ========= ========= ========= Balance Sheet: Current assets $ 10,088 $ 10,105 $ 12,974 Non-current assets 67,855 49,300 35,034 Current liabilities 6,595 10,569 11,700 Non-current liabilities 66,223 50,614 48,007 Shareholders' equity (deficit) 5,125 (1,778) (11,699) F-20 12. Real Estate Assets: In a prior year the Company made the decision to sell its remaining real estate projects. Accordingly, the Company's real estate activities since that time have been presented as discontinued operations in the statements of income. The Company's remaining real estate assets consist of land held for sale with a carrying cost of $1,386,000 and $1,311,000 as of December 31, 1996 and 1995, respectively, which is less than the estimated net realizable values. 13. Disclosures About Oil and Gas Producing Activities: Major Customers: During 1996, sales to an individual customer constituted 17.3% of total revenues. There were no sales to individual customers constituting 10% or more of total revenues during 1995 and 1994. Costs Incurred in Oil and Gas Producing Activities: Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows: For the Years Ended December 31, -------------------------------- 1996 1995 1994 -------- -------- -------- (In thousands) Development costs $16,709 $12,625 $ 5,946 Exploration costs: Domestic 11,910 8,746 9,481 International 84 (112) 877 Acquisitions Proved 20,957 8,111 12,279 Unproved 2,941 2,937 3,228 -------- -------- -------- Total $52,601 $32,307 $31,811 ======== ======== ======== Russian joint venture, equity method (a) $ 3,881 $ 3,213 $ 1,551 ======== ======== ======== - ----------- (a) In February 1997, the Company sold its interest in the Russian joint venture (see note 11). In June 1996, the Company completed the purchase of a 90% interest in certain of the assets of Siete Oil & Gas Corporation for approximately $10.0 million. The assets purchased consist primarily of oil and gas producing properties in the Permian Basin of west Texas and southeast New Mexico. The accompanying unaudited pro forma consolidated operating revenues, income from continuing operations and income per common share from continuing operations for the years ended December 31, 1996 and 1995 are presented to illustrate the effect of the properties purchased from Siete Oil & Gas Corporation on the Company's results of operations as if the transaction had occurred as of January 1, 1995. F-21 The resulting pro-forma information is not necessarily indicative of the results of operations of the Company as they may be in the future or as they might have been had the transaction actually occurred as of January 1, 1995. Pro Forma for the Years Ended December 31, ------------------------ 1996 1995 -------- -------- (Unaudited) (in thousands, except per share amounts) Total operating revenues $ 61,189 $ 42,015 ======== ======== Income from continuing operations $ 10,561 $ 2,142 ======== ======== Income per common share from continuing operations $ 1.20 $ .25 ======== ======== Oil and Gas Reserve Quantities (Unaudited): The reserve information as of December 31, 1996, 1995, 1994 and 1993 was prepared by the Company and Ryder Scott Company. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. F-22 Presented below is a summary of the changes in estimated domestic reserves of the Company and its share of the Russian joint venture reserves:
For the Years Ended December 31, --------------------------------------------------------------- 1996 1995 1994 ------------------- ------------------- ------------------- Oil or Oil or Oil or Condensate Gas Condensate Gas Condensate Gas -------- -------- -------- -------- -------- -------- (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MMCF) Total proved U.S. reserves: Developed and undeveloped: Beginning of year 7,509 75,705 6,677 62,515 4,590 56,535 Revisions of previous estimates 706 6,706 39 515 446 5,064 Discoveries and extensions 1,343 44,018 894 16,069 658 10,274 Purchase of minerals in place 2,625 16,894 1,095 9,274 2,062 3,262 Sale of reserves (306) (703) (152) (234) (142) (43) Production (1,186) (15,563) (1,044) (12,434) (937) (12,577) -------- -------- -------- -------- -------- -------- End of year (a) 10,691 127,057 7,509 75,705 6,677 62,515 ======== ========= ======== ======== ======== ======== Proved developed U.S. reserves: Beginning of year 6,829 66,230 6,050 58,661 4,160 54,420 ======== ========= ======== ======== ======== ======== End of year 10,015 100,027 6,829 66,230 6,050 58,661 ======== ========= ======== ======== ======== ======== Russian joint venture reserves: End of year (b) 7,146 2,444 7,247 2,536 9,915 - ======== ========= ======== ======== ======== ======== - ----------- (a) At December 31, 1996, 1995 and 1994, includes approximately 1,622, 1,895 and 2,500 MMCF, respectively representing the Company's underproduced gas balancing position. (b) In February 1997, the Company sold its interest in the Russian joint venture (see note 11).
Standardized Measure of Discounted Future Net Cash Flows (Unaudited): SFAS No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates, including consideration for estimated future statutory depletion and alternative fuels tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. F-23 The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS No. 69: As of December 31, -------------------------------------- 1996 1995 1994 ---------- ---------- ---------- (In thousands) Future cash inflows $ 691,945 $ 292,149 $ 202,454 Future production and development costs (196,677) (105,520) (73,204) Future income taxes (155,805) (49,383) (28,977) ---------- ---------- ---------- Future net cash flows 339,463 137,246 100,273 10% annual discount (136,233) (49,547) (39,407) ---------- ---------- ---------- Standardized measure of discounted future net cash flows $ 203,230 $ 87,699 $ 60,866 ========== ========== ========== Russian joint venture standardized measure of discounted future net cash flows (a) $ 23,681 $ 15,077 $ 25,242 ========== ========== ========== - ----------- (a) In February 1997, the Company sold its interest in the Russian joint venture (see note 11). F-24 The principal sources of change in the standardized measure of discounted future net cash flows are as follows: For the Years Ended December 31, ------------------------------------ 1996 1995 1994 ---------- ---------- ---------- (In thousands) Standardized measure, beginning of year $ 87,699 $ 60,866 $ 64,491 Sales of oil and gas produced, net of production costs (43,877) (25,923) (27,743) Net changes in prices and production costs 71,882 23,432 (16,196) Extensions, discoveries and other, net of production costs 90,974 23,863 12,507 Purchase of minerals in place 26,241 10,287 11,114 Development costs incurred during the year 6,833 2,189 1,655 Changes in estimated future development costs (1,166) (1,801) (1,227) Revisions of previous quantity estimates 19,350 856 6,941 Accretion of discount 12,019 8,469 9,052 Sales of reserves in place (1,224) (1,365) - Net change in income taxes (61,459) (12,817) 6,771 Other (4,041) (357) (6,499) ---------- ---------- ---------- Standardized measure, end of year (a) $ 203,230 $ 87,699 $ 60,866 ========== ========== ========== - ----------- (a) The standardized measure was based on a year-end gas price of $3.74 per MMBTU and a year-end oil price of $25.08 per BBL. Using these prices the present value of future net revenues discounted at 10% before tax is $296 million. Using more conservative pricing of $2.25 per MMBTU for gas and $21.00 per BBL for oil, the present value of future net revenues discounted at 10% before tax would be $170 million. 14. Subsequent Event: On January 28, 1997, the Company filed a Form S-3 Registration Statement with the Securities and Exchange Commission, as a new financing, to register the sale by the Company of 2,000,000 shares of common stock and up to an additional 300,000 shares to cover the underwriters' over-allotment option. On February 26, 1997 the Company closed the sale of the 2,000,000 shares of common stock at $25.00 per share. On March 12, 1997, the Company closed the sale of an additional 180,000 shares pursuant to the underwriters' exercise of the over-allotment option. These transactions resulted in aggregate net proceeds of $51.3 million. The proceeds will be used to fund the Company's exploration, development and acquisition programs, and pending such use will be used to repay borrowings under its credit facility. As of March 21, 1997, the Company has repaid all borrowings under its credit facility, and effective April 1, 1997, has reduced its commitment under this facility, until its next redetermination, to $10 million. The Company has the right to increase its commitment between redetermination periods. F-25 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ST. MARY LAND & EXPLORATION COMPANY ----------------------------------- (Registrant) Date: March 27, 1997 By: /s/ THOMAS E. CONGDON --------------------- Thomas E. Congdon, Chairman of the Board GENERAL POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Thomas E. Congdon and Mark A. Hellerstein, and each of them, his true and lawful attorney-in-fact and agents with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any amendments to this report on Form 10-K, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Title Date - --------- ----- ---- /s/ THOMAS E. CONGDON Chairman of the Board of March 27, 1997 ------------------- Directors and Director Thomas E. Congdon /s/ MARK A. HELLERSTEIN President, Chief Executive March 27, 1997 ------------------- Officer, and Director Mark A. Hellerstein /s/ RONALD D. BOONE Executive Vice President, March 27, 1997 ------------------- Chief Operating Officer Ronald D. Boone and Director Signature Title Date - --------- ----- ---- /s/ DAVID L. HENRY Vice President-Finance March 27, 1997 ------------------- and Chief Financial David L. Henry Officer /s/ RICHARD C. NORRIS Vice President, Treasurer March 27, 1997 ------------------- and Chief Accounting Richard C. Norris Officer /s/ LARRY W. BICKLE Director March 27, 1997 ------------------- Larry W. Bickle /s/ DAVID C. DUDLEY Director March 27, 1997 ------------------- David C. Dudley /s/ RICHARD C. KRAUS Director March 27, 1997 ------------------- Richard C. Kraus /s/ R. JAMES NICHOLSON Director March 27, 1997 ------------------- R. James Nicholson /s/ AREND J. SANDBULTE Director March 27, 1997 ------------------- Arend J. Sandbulte /s/ JOHN M. SEIDL Director March 27, 1997 ------------------- John M. Seidl