As filed with the Securities and Exchange Commission on January 28, 1997 Securities Act File No. 333- U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM S-3 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ST. MARY LAND & EXPLORATION COMPANY (Exact Name of Registrant as Specified in its Charter) Delaware 41-0518430 (State or Other Jurisdiction of (IRS Employer Incorporation or Organization) Identification Number) 1776 Lincoln Street, Suite 1100 Denver, Colorado 80203 (303) 861-8140 Fax: (303) 861-0934 (Address, including Zip Code, and Telephone Number, including Area Code, of Registrant's Principal Executive Offices) MARK A. HELLERSTEIN, President and Chief Executive Officer 1776 Lincoln Street, Suite 1100 Denver, Colorado 80203 (303) 861-8140 Fax: (303) 861-0934 (Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service) Copies to: Roger V. Davidson, Esq. George G. Young III, Esq. Dwight R. Landes, Esq. Butler & Binion, L.L.P. Cohen Brame & Smith 1000 Louisiana, Suite 1600 Professional Corporation Houston, Texas 1700 Lincoln Street, Suite 1800 (713) 237-3605 Denver, Colorado 80203 Fax: (713) 237-3202 (303) 837-8800 Fax: (303) 894-0475 Approximate date of commencement of proposed sale to public: As soon as practicable after the registration statement becomes effective If the only securities being registered on this Form are being offered pursuant to dividend or interest investment plans, please check the following box. [ ] If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box. [ ] If this Form is being filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If the delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] CALCULATION OF REGISTRATION FEE Title of Proposed Proposed Amount each Class of Maximum Maximum of Securities Amount Offering Aggregate Regi- to be to be Price per Offering stration Registered Registered Share Price Fee Common Stock 2,300,000(1) $28.5625(2) $65,693,750(3) $19,908 $0.01 par value (1) Includes 300,000 shares to cover the Underwriters' over-allotment option, if exercised. (2) The average of the high and low prices reported on the Nasdaq National Market as of January 24, 1997. (3) Estimated solely for the purpose of determining the registration fee and calculated pursuant to Rule 457(a). _____________________ The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. SUBJECT TO COMPLETION, DATED JANUARY 27, 1997 [LOGO] 2,000,000 Shares ST. MARY LAND & EXPLORATION COMPANY Common Stock All of the shares of Common Stock, par value $0.01 per share ("Common Stock"), of St. Mary Land & Exploration Company ("St. Mary" or the "Company") offered hereby are being sold by the Company. The Common Stock is traded on the Nasdaq National Market under the trading symbol "MARY". The last reported sale price of the Common Stock on the Nasdaq National Market on January 22, 1997, was $29 1/4 per share. See "Risk Factors" beginning on page 9 for a discussion of certain factors that should be considered in connection with an investment in the Common Stock offered hereby. THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. Price to Underwriting Proceeds to Public Discount(1) Company(2) Per Share Total (1) The Company has agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended. See "Underwriting." (2) Before deducting expenses of the offering payable by the Company estimated at $_________. (3) The Company has granted the several Underwriters an option for 30 days to purchase up to an additional 300,000 shares of Common Stock at the Price to Public, less Underwriting Discount, solely to cover over-allotments, if any. If such option is exercised in full, the total Price to Public, Underwriting Discount and Proceeds to Company will be $_____________, $____________ and $______________, respectively. See "Underwriting." ____________________ The shares of Common Stock are offered by the several Underwriters, subject to prior sale, when, as and if issued to and accepted by them, and subject to certain other conditions. The Underwriters reserve the right to withdraw, cancel or modify such offer and to reject orders in whole or in part. It is expected that delivery of the shares of Common Stock will be made on or about ________________, 1997. MORGAN KEEGAN & COMPANY, INC. A.G. EDWARDS & SONS, INC. HANIFEN, IMHOFF INC. The date of this Prospectus is ____________, 1997 MAP OF U.S. DEPICTING AREAS OF ST. MARY'S OPERATIONS SHOWING OUTLINES OF STATES AND COLORS HIGHLIGHTING AREAS OF OPERATIONS IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE SECURITIES OFFERED HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON STOCK OF THE COMPANY ON THE NASDAQ NATIONAL MARKET IN ACCORDANCE WITH RULE 10b-6A UNDER THE SECURITIES EXCHANGE ACT OF 1934. SEE "UNDERWRITING." PROSPECTUS SUMMARY The following summary is qualified in its entirety by the detailed information and financial statements found elsewhere in this Prospectus and the information incorporated herein by reference. Unless otherwise indicated, all information in this Prospectus assumes no exercise of the Underwriters' over-allotment option. See "Underwriting." As used in this Prospectus, the terms "St. Mary" and the "Company" refer to St. Mary Land & Exploration Company and its subsidiaries, unless otherwise stated or indicated by the context. Certain terms used herein relating to the oil and gas industry are defined in the "Glossary" included elsewhere in this Prospectus. Investors should carefully consider the information set forth in "Risk Factors." The Company St. Mary Land & Exploration 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 tri-state area of southern Arkansas, northern Louisiana and eastern Texas ("ArkLaTex"); 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 $4.15 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 $3.50 per BOE. In 1996, the Company's estimated net proved reserve additions replaced 424% of production, including 247% from drilling, 124% from property acquisitions and 53% from revisions. The Company's 1997 capital budget of $65 million includes (i) $43 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 million for niche acquisitions of properties and (iii) $7 million for high-risk, large-target exploration prospects. 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 3-D 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 spent approximately $31 million on development and exploration, including participation in 117 successful gross wells reflecting an overall 82% success rate. 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 seven 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 is presently being completed. 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 totalling $41.5 million at an average acquisition cost of $3.89 per BOE. Strategic Relationships. Throughout its 89-year history the Company has 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. Core Operating Areas Continuing investment in technical staff, oil and gas leases, geological studies, 3-D seismic data and advanced well completion techniques has generated expanded exploration, development and acquisition opportunities for St. Mary in each of its core operating areas. Mid-Continent Region. St. Mary has been active in the Mid-Continent region since 1973 where its operations are managed by the Company's 25-person, Tulsa, Oklahoma office. During 1996 the Company participated in 75 gross wells and recompletions, including 17 Company-operated wells. The Mid-Continent region accounted for 34% of the Company's estimated net proved reserve volumes as of December 31, 1996 (92% proved developed and 94% gas). The Company's 1997 Mid-Continent capital budget of approximately $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. The Company has arranged commitments for three drilling rigs in the Mid-Continent region throughout 1997 and plans to drill as operator 25 to 30 gross wells in the area, and to participate in an additional 30 gross wells. In addition, St. Mary has a 24% working interest in a large-target prospect in the Cotton Valley Reef play of east Texas. ArkLaTex Region. St. Mary first acquired an interest in the ArkLaTex region in 1992, and has since completed 8 additional acquisitions of producing properties and undertaken an active program of development and exploration in the area. St. Mary s existing lease position totals 46,000 gross acres and the Company owns over 6,000 miles of proprietary 2-D seismic data in the region. The ArkLaTex region, which accounted for 27% of the Company's estimated net proved reserve volumes as of December 31, 1996 (58% proved developed and 87% gas), is managed by St. Mary's 12-person office in Shreveport, Louisiana. In 1996 the Company made a significant discovery in its Box Church Field in east Texas which added 26.4 Bcf of estimated net proved reserves. The Company's 1997 capital budget provides $7.5 million for ongoing development and exploration in the region, including a 12-well development program in the Box Church Field. 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 the region. The south Louisiana region accounted for 5% of the Company's estimated net proved reserve volumes as of December 31, 1996 (100% proved developed and 84% gas). St. Mary owns approximately 24,900 acres of fee lands and associated oil and gas royalty interests on these lands which include the Bayou Sale, Horseshoe Bayou and Belle Isle Fields. In granting new leases on its fee lands the Company seeks to retain the right to participate as a 25% working interest owner in new wells. The completion and interpretation of two 3-D seismic surveys by the Company's lessees and the completion of St. Mary's own detailed geological and engineering studies have contributed to renewed development and exploration activity on the Company's fee lands, including additional drilling and recompletion work as well as exploration interest in deeper, untested horizons. St. Mary's historical presence in south Louisiana, its established network of industry relationships and its extensive technical database have enabled the Company to assemble an inventory of large-target prospects in this region, including two deep gas prospects which are located on the Company's fee lands and are scheduled to be tested during 1997. Williston Basin Region. The Williston Basin region accounted for 20% of the Company's estimated net proved reserve volumes as of December 31, 1996 (93% proved developed and 90% oil). St. Mary's operations in this basin are conducted through Panterra which owns interests in approximately 360 gross producing wells located in 60 fields. Since 1991, the Company's investment in Panterra has totaled approximately $26 million and has included participation in 11 Panterra-operated development and exploration wells with a 100% success rate. The Company's successful exploration and development in the basin have resulted from the application of state-of-the-art 3-D seismic imaging to delineate structural features together with porosity development. In 1994, the Company conducted a 4.5 square mile 3-D seismic survey at the North Bainville Field which led to the successful 1995 extension of the field in the Red River formation. During 1996, St. Mary completed an additional four wells at North Bainville and conducted an additional 21 square mile 3-D seismic survey in the area. The Company has also begun to apply the experience gained at North Bainville to other fields in the basin where Panterra holds significant leasehold interests, including the Brush Lake and Nameless Fields where Panterra completed separate 3-D seismic surveys in late 1995 and early 1996. The 1997 capital budget provides $6 million for ongoing development and exploration in the basin. Permian Basin Region. The Permian Basin of New Mexico and west Texas is the Company's newest area of concentration. Management believes this region provides St. Mary with a solid base of long-lived oil reserves, promising longer-term exploration and development prospects and potential for water flood secondary recovery projects. The Company established a presence in the basin in 1995 through the acquisition of a 21.2% working interest in a 30,450 acre top lease in Ward and Winkler Counties, Texas which is believed to hold significant exploration potential in the virtually untested deeper formations on the lease. St. Mary increased its holdings in the region during 1996 with the acquisition of a 90% interest in the producing properties of Siete Oil and Gas Company for $10.0 million. The Permian Basin region accounted for 12% of the Company's estimated net proved reserve volumes as of December 31, 1996 (96% proved developed and 81% oil). Recent Developments Russian Partnership Interest. In order to focus on development and exploration efforts in its five core operating areas, the Company decided in 1996 to monetize its interests in properties in Russia ("Russian Partnership Interest"). Upon the closing, which the Company expects to occur in the first quarter of 1997, the Company will receive cash consideration of approximately $5.2 million, approximately $1.7 million of common stock in Ural Petroleum Corporation and a receivable in the form of a retained production payment of $10.3 million plus interest at 10% per annum. See "Business and Properties - Other Activities." Risk Factors See "Risk Factors" for a discussion of certain factors that should be considered in connection with an investment in the Common Stock offered hereby. The Offering Common Stock offered by the Company......................2,000,000 Common Stock to be outstanding after the Offering.....10,759,214(1) Use of Proceeds................... The net proceeds of the offering, together with internally generated cash flows and borrowings under the Company's credit facility with a commercial bank ("Credit Facility"), will be utilized to fund the Company's exploration and development activities and potential acquisitions and for general corporate purposes. Pending utilization of the net proceeds, the funds will be used to repay revolving bank loans and to the extent that net proceeds are in excess of amounts outstanding under the Credit Facility, the Company will invest in short-term investments. Nasdaq National Market Symbol..... "MARY" (1) Excludes 97,495 shares of Common Stock issuable upon exercise of options outstanding as of January 22, 1997 and 262,372 shares underlying options to be issued in exchange for the Company's Stock Appreciation Rights ("SAR"). See "Management's Discussion and Analysis of Financial Condition and Results of Operations." Summary Consolidated Financial Data (In thousands, except per share data) The following table sets forth certain consolidated financial data for the Company as of and for each of the periods indicated. The financial data for each year in the three-year period ended December 31, 1995, are derived from the audited financial statements of the Company. The financial data for the nine month periods ended September 30, 1995 and 1996 are derived from the Company's unaudited financial statements which, in the opinion of management of the Company, have been prepared on the same basis as the annual consolidated financial statements and include all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the financial data for such periods. 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 Prospectus. The results for the nine months ended September 30, 1996 are not necessarily indicative of results for the full year. Historical financial data are not necessarily predictive of the Company's future results of operations and financial condition. Nine Months Ended September Year Ended December 31, 30, 1993 1994 1995 1995 1996 (Unaudited) Income Statement Data: Operating revenues: Oil and gas production $38,208 $38,239 $36,569 $25,860 $39,689 Gas contract settlements and other 424 6,546 2,081 1,580 490 Total operating revenues 38,632 44,785 38,650 27,440 40,179 Operating expenses: Oil and gas production 9,341 10,496 10,646 7,676 9,262 Depletion, depreciation and amortization 8,775 10,134 10,227 7,184 9,144 Impairment of proved properties(1) 3,498 4,219 2,676 1,673 - Exploration 5,457 8,104 5,073 3,683 5,688 Abandonment and impairment of unproved properties 1,020 1,023 2,359 759 1,240 General and admini- strative (2) 4,712 5,261 5,328 4,129 5,066 Other 1,297 841 731 470 64 Total operating expenses 34,100 40,078 37,040 25,574 30,464 Income from operations 4,532 4,707 1,610 1,866 9,715 Net interest expense 62 525 896 514 1,180 Income from continuing operations before income taxes 4,470 4,182 714 1,352 8,535 Income tax expense (benefit) 1,065 445 (723) 72 (2,773) Gain on sale of discontinued operations, net of taxes - - 306 231 159 Cumulative effect of change in accounting principle 300 - - - - Net income $ 3,705 $ 3,737 $ 1,743 $ 1,655 $ 5,921 Net income per common share: Income from continuing operations $0.39 $0.43 $0.17 $0.16 $0.66 Gain on sale of discontinued operations - - 0.03 0.03 0.02 Cumulative effect of change in accounting principle 0.03 - - - - Net income per share $0.42 $0.43 $0.20 $0.19 $0.68 Dividends paid per share $0.16 $0.16 $0.16 $0.12 $0.12 Weighted average common shares outstanding 8,763 8,763 8,760 8,760 8,759 Other Data: EBITDA (3) $13,307 $14,841 $11,837 $ 9,050 $18,859 Net cash provided by operating activities 19,675 20,271 17,713 11,755 17,110 Capital and exploration expenditures(4) 22,787 30,934 32,419 23,591 36,680 September 30, 1996 Actual As Adjusted(5) (Unaudited) Balance Sheet Data: Working capital. . . . . . $ 7,602 $ _____ Net property and equipment . . 92,804 92,804 Total assets. . . . . . . .132,680 _____ Long-term debt . . . 36,324 - Total stockholders' equity . . 71,140 _____ (1) 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. (2) Includes compensation expense recognized under the Company's SAR plan of $222,191, $268,286 and $220,247 in 1993, 1994 and 1995, respectively, and $243,000 and $604,000 during the nine months ended September 30, 1995 and 1996, respectively. In November 1996, the Company replaced the SAR plan with a stock option plan, and accordingly SAR expense will be significantly lower in 1997. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Accounting Matters." (3) EBITDA is defined as income before income taxes, interest, 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. (4) Excludes certain international exploration costs. See "Management's Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources Capital and Exploration Expenditures." (5) As adjusted to give effect to the sale of 2,000,000 shares of Common Stock offered hereby and the application of the estimated net proceeds of approximately $__________. See "Use of Summary Reserve Data The following table sets forth summary information with respect to the Company's estimated net proved reserves as of December 31, 1994, 1995 and 1996, as prepared by Ryder Scott Company ("Ryder Scott"), independent petroleum engineers, and by the Company. As of December 31, 1994 1995 1996 Reserve Data: (1) Oil (MBbls) . . . . . . . 6,677 7,509 10,691 Gas (MMcf). . . . . . . .62,515 75,705 127,057 MBOE . . . . . . . . . .17,096 20,127 31,867 PV-10 Value (in thousands) $84,688 $120,192 $296,461 Proved developed reserves (%) . . . . . . . 93% 89% 84% Production replacement (%) . . . . . 207% 203% 424% Reserve Life (years). . . . 6.1 6.5 7.2 (1) For limitations on the accuracy and reliability of estimated net proved reserves and future net revenue estimates, see "Risk Factors - Uncertainty of Estimates of Net Proved Reserves." See also "Business and Properties - Estimated Net Proved Reserves." Reserve data attributable to the Company's Russian Partnership Interest have been excluded from this table. The Company has agreed to monetize its Russian Partnership Interest, and the closing is expected to occur in the first quarter of 1997. See "Business and Properties - Other Activities." Summary Operating Data Nine Months Ended Year Ended December 31, September 30, 1993 1994 1995 1995 1996 Operating Data:(1) Net production: Oil (MBbls) 846 937 1,044 764 865 Gas (MMcf) 11,147 12,577 12,434 8,961 11,249 MBOE 2,704 3,033 3,116 2,258 2,739 Average net daily production: Oil (Bbls) 2,319 2,567 2,852 2,798 3,156 Gas (Mcf) 30,539 34,458 33,973 32,824 41,053 BOE 7,408 8,310 8,514 8,270 9,998 Average realized sales price:(2) Oil (per Bbl) $16.17 $14.95 $16.35 $16.33 $18.27 Gas (per Mcf) $ 2.20 $ 1.93 $ 1.56 $ 1.49 $ 2.12 Additional per BOE data: Lease operating expenses $ 2.42 $ 2.54 $ 2.49 $ 2.51 $ 2.28 Production taxes $ 1.04 $ 0.92 $ 0.93 $ 0.89 $ 1.10 Depletion, depreciation and amortization$ 3.25 $ 3.34 $ 3.28 $ 3.18 $ 3.34 (1) Excludes operating data attributable to the Company's Russian Partnership Interest. (2) Includes the effects of the Company's hedging activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview." RISK FACTORS In addition to the other information contained in this Prospectus, the following factors relating to the Company and this offering should be considered carefully when evaluating an investment in the shares of Common Stock offered hereby. This Prospectus, including the documents incorporated by reference, 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 (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical facts, included in this Prospectus 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, including the risk factors discussed below, 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. Prospective investors 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. Volatility of Oil and Gas Prices and Markets The Company's revenues, cash flow, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas. The Company's ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on oil and gas prices. Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include international political conditions, the domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels and overall economic conditions. In addition, various factors, including the availability and capacity of gas gathering systems and pipelines, the effect of federal and state regulation of production and transportation, general economic conditions, changes in supply due to drilling by other producers and changes in demand may adversely affect the Company's ability to market its oil and gas production. Any significant decline in the price of oil or gas would adversely affect the Company's revenues, operating income and borrowing capacity and may require a reduction in the carrying value of the Company's oil and gas properties. Replacement of Reserves The Company's future success depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Except to the extent that the Company conducts successful exploration or development activities or acquires properties containing proved reserves, the estimated net proved reserves of the Company will generally decline as reserves are produced. There can be no assurance that the Company's planned development and exploration projects and acquisition activities will result in significant additional reserves or that the Company will have continuing success drilling productive wells at economic Finding Costs. If prevailing oil and gas prices were to increase significantly, the Company's Finding Costs to add new reserves could increase. The drilling of oil and gas wells involves a high degree of risk, especially the risk of dry holes or of wells that are not sufficiently productive to provide an economic return on the capital expended to drill the wells. In addition, the Company's drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and availability of drilling rigs. Certain of the Company's oil and gas properties are operated by third parties and as a result the Company has limited control over the nature and timing of exploration and development of such properties or the manner in which operations are conducted on such properties. A significant portion of the Company's cash flow is attributable to royalty interests on its south Louisiana fee properties. Without continued exploration on and development of the fee properties, which the Company has only a limited ability to control, production and cash flow from these properties will decline. Uncertainty of Estimates of Reserves and Future Net Revenues This Prospectus, including the documents incorporated by reference, includes estimates of the Company's net proved oil and gas reserves and the future net revenues from those reserves which have been prepared by the Company and its independent petroleum engineers. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating the underground accumulations of oil and gas that cannot be measured in an exact manner. The estimates in this Prospectus are based on various assumptions required by the Securities and Exchange Commission (the "Commission"), including constant oil and gas prices, operating expenses and capital expenditures, and, therefore, are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this Prospectus. In addition, the Company's reserves may be subject to downward or upward revision based upon production history, results of future development, availability of funds to acquire additional reserves, prevailing oil and gas prices and other factors. In addition, the calculation of the estimated present value of the future net revenue using a 10% discount rate as required by the Commission is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company's reserves or the oil and gas industry in general. See "Business and Properties - Estimated Net Proved Reserves." It is also possible that reserve engineers may make different estimates of reserves and future net revenues based on the same available data. In calculating reserves on a BOE basis, gas was converted to oil at the ratio of six Mcf of gas to one Bbl of oil. While this convention approximates the energy equivalent of oil and gas on a Btu basis, it may not represent the relative prices received by the Company on the sale of its oil and gas production. The estimated future net revenues attributable to the Company's net proved reserves are prepared in accordance with Commission guidelines, and are not intended to reflect the fair market value of the Company's reserves. In accordance with the rules of the Commission, the Company's reserve estimates are prepared using period end prices received for oil and gas. For year end 1996, these prices were materially higher than for year end 1995 and 1994. Future reductions in prices below those prevailing at year end 1996 would result in the estimated quantities and present values of the Company's reserves being reduced. Operating Hazards and Uninsured Risks 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. Substantial Capital Requirements The Company makes, and will continue to make, substantial capital expenditures for the development, exploration and acquisition and production of oil and gas reserves. Historically, the Company has financed these expenditures primarily with the proceeds of bank borrowings, the sale of Common Stock and cash generated by operations. Management believes that the net proceeds of this offering, bank borrowings and cash generated from operations will be sufficient to fund its planned operations through 1997. If revenues or the Company's borrowing base decrease as a result of lower oil and gas prices, operating difficulties or declines in reserves, the Company may have limited ability to fund the capital requirements to undertake or complete future development and exploration programs. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." Acquisition Risks The Company intends to continue acquiring oil and gas properties. See "Business and Properties -- Business Strategy." Although the Company performs a review of the acquired properties that it believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, the Company will focus its due diligence efforts on the higher valued properties and will sample the remainder. However, even an in-depth review of all properties and records may not necessarily reveal existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. The Company may be required to assume preclosing liabilities, including environmental liabilities, and may acquire interests in properties on an "as is" basis. There can be no assurance that the Company's acquisitions will be successful. Risks of Fixed Price Sales and Hedging Contracts The Company manages the risk associated with fluctuations in the price of gas and oil, primarily through certain fixed price sales and hedging contracts. The Company's price risk management strategy reduces the Company's sensitivity to changes in market prices of oil and gas, but is subject to a number of other risks. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview." Competition The oil and gas industry is highly competitive. The Company competes in the areas of property acquisitions and the development, production and marketing of oil and gas with major oil companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have substantially greater financial and other resources than the Company. See "Business and Properties -- Competition." Governmental Regulation and Environmental Risks 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. 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 of 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. Continuing Control by Existing Stockholders The Chairman of the Board of Directors and members of his extended family own approximately 45% of the outstanding Common Stock of the Company. While no formal arrangements exist, these extended family members may be inclined to act in concert with the Chairman on matters related to control of St. Mary, including for example, the election of directors or relative to an unsolicited bid to acquire the Company. While the percentage ownership of the extended family of the Chairman will be reduced by approximately 9% after the offering, the Chairman and his extended family may be able to control or influence matters presented to the stockholders. Risks Specific to the Company's Investment in Other Activities The Company has invested a total of approximately $5.9 million to acquire a 49.9% interest in Summo Minerals Corporation ("Summo Minerals"). Summo Minerals is engaged in the business of development of certain copper projects, the principal one being located in southeast Utah. If Summo Minerals is unable to raise the capital needed to fund the development of its first project, the Company currently expects to invest no more than approximately $1.0 to $2.0 million in Summo Minerals in 1997. There can be no assurance that the Company's investment in Summo Minerals will be successful or that it will ever recover its investment. See "Business and Properties -- Other Activities." USE OF PROCEEDS The net proceeds from this offering are estimated to be $[__________] ($__________ if the Underwriters' over-allotment option is exercised in full), after deducting the underwriting discount and estimated offering expenses. The Company intends to use such net proceeds, together with internally generated funds and borrowings under St. Mary's bank credit facility ("Credit Facility") and Panterra's bank credit facility ("Panterra Credit Facility"), to fund its 1997 capital budget estimated to total $65 million and for general corporate purposes. The following table sets forth the estimated allocation of the Company's 1997 capital budget (in millions): Ongoing Exploration and Development Projects: Mid-Continent Region $26.5 ArkLaTex Region 7.5 Williston Basin 6.0 Permian Basin 2.0 Other 1.0 Large-Target Exploration Projects 7.0 Acquisitions 15.0 Total $65.0 Pending use of funds, the Company will use the net proceeds of this offering to repay borrowings under its Credit Facility. To the extent that net proceeds are in excess of amounts outstanding under the Credit Facility, the Company will invest in short-term investments. Amounts repaid under the revolving loan provisions of the Credit Facility, which expire in June 1999, will be available for re-borrowing (subject to borrowing base limitations and other restrictions) until the Credit Agreement expires, or until borrowings are converted, at the option of the Company, into a term loan if earlier. As of January 17, 1997, borrowings of $36.4 million were outstanding under the Credit Facility, with a weighted average interest rate of 6.5%. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Credit Facility." CAPITALIZATION The following table sets forth the capitalization of the Company as of September 30, 1996 and as adjusted to reflect the sale of the 2,000,000 shares of Common Stock offered by the Company hereby and the application of the estimated net proceeds of $__________ therefrom as described under "Use of Proceeds." This table should be read in conjunction with the Consolidated Financial Statements and notes thereto included in this Prospectus. September 30, 1996 Actual As Adjusted (unaudited) (in thousands) Cash and cash equivalents . . . . $ 4,405 $ Long-term debt: Credit Facility(1) . . . . . . 25,350 - Panterra Credit Facility(2). . . 10,974 10,974 Total long-term debt . . . . . . . 36,324 10,974 Stockholders' equity(3): Common Stock, $.01 par value, 15,000,000 shares authorized; 8,759,214 shares issued and outstanding; 10,759,214 shares as adjusted. . . . . . . 85 Additional paid-in capital. . . 15,803 _____ Retained earnings . . . . . . .. 55,248 55,248 Unrealized gain on marketable equity securities - available for sale . . . . . . . 4 4 Total stockholders' equity. . . . 71,140 _____ Total capitalization . . . . . . $107,464 $ (1) As of January 17, 1997, the Credit Facility had an outstanding balance of $36.4 million. (2) The Company has a 74% general partnership interest in Panterra and proportionately consolidates the outstanding balance of the Panterra Facility. See Notes 1 and 5 to the Consolidated Financial Statements as of December 31, 1995 and 1994, and for each of the three years in the period ended December 31, 1995 included herein. (3) Excludes 97,495 shares of Common Stock issuable upon exercise of options outstanding as of January 22, 1997 and 262,372 shares underlying options to be issued in exchange for the Company's SAR. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." PRICE RANGE OF COMMON STOCK The Company's Common Stock is traded on the Nasdaq National Market under the symbol "MARY." The following table sets forth the high and low closing sale prices for the periods presented: High Low Year Ended December 31, 1995: First Quarter. . . . . . $14 $12 1/2 Second Quarter . . . . . 13 5/8 10 7/8 Third Quarter. . . . . . 14 7/8 12 7/8 Fourth Quarter . . . . . 15 13 1/4 Year Ended December 31, 1996: First Quarter. . . . . . $16 5/8 $13 1/2 Second Quarter . . . . . 17 7/8 15 7/8 Third Quarter. . . . . . 17 14 1/4 Fourth Quarter . . . . . 27 3/8 16 1/2 Year Ending December 31, 1997: First Quarter (through January ___, 1997) $ $ On January 22, 1997, the closing sale price for the Common Stock as reported on the Nasdaq National Market was $29 1/4 per share. As of January 1, 1997, the number of record holders of the Company's Common Stock was 154. Management believes, after inquiry, that the number of beneficial owners of the Company's Common Stock is in excess of 1,100. DIVIDEND POLICY The Company has paid cash dividends on its Common Stock for the past 57 consecutive years. For the last nine years, the Company has paid cash dividends of $.16 per share per year. The Company increased its quarterly dividend to $.05 per share or $.20 per share per year effective with the quarterly dividend declared in January 1997 and payable in February 1997. The Company currently intends to continue to pay comparable annual cash dividends on its outstanding shares of Common Stock on a quarterly basis. The terms of the Company's Credit Facility contain restrictions on the payment of cash dividends to holders of Common Stock. Accordingly, the Company's ability to pay cash dividends will depend upon such restrictions and the Company's results of operations, financial condition, capital requirements and other factors deemed relevant by the Board of Directors. 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, 1995, were derived from the Consolidated Financial Statements of the Company which have been audited by Coopers & Lybrand L.L.P., independent accountants. The data set forth in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the notes thereto presented elsewhere or incorporated by reference in this Prospectus. Nine Months Ended Year Ended December 31, September 30, 1991 1992 1993 1994 1995 1995 1996 Income Statement Data: Operating Revenues: Oil production 7,608 11,949 13,685 14,006 17,090 12,473 15,799 Gas production 19,407 23,296 24,523 24,233 19,479 13,387 23,890 Gas contract settlements and other 773 15,413 424 6,546 2,081 1,580 490 Total operating revenues 27,788 50,658 38,632 44,785 38,650 27,440 40,179 Operating Expenses: Oil and gas production 4,522 7,793 9,341 10,496 10,646 7,676 9,262 Depletion, depreciation and amortization 5,586 6,213 8,775 10,134 10,227 7,184 9,144 Impairment of proved properties (1) 790 1,565 3,498 4,219 2,676 1,673 - Exploration 4,133 3,615 5,457 8,104 5,073 3,683 5,688 Abandonment and impairment of unproved properties 2,434 1,264 1,020 1,023 2,359 759 1,240 General and administrative (2) 3,187 4,544 4,712 5,261 5,328 4,129 5,066 Gas contract disputes and other 750 1,332 638 493 152 184 111 Loss (income) in equity investees --- 1,026 659 348 579 286 (47) Total operating expenses 21,402 27,352 34,100 40,078 37,040 25,574 30,464 Income from operations 6,386 23,306 4,532 4,707 1,610 1,866 9,715 Non-operating expense 1,000 791 62 525 896 514 1,180 Income tax expense (benefit) 1,874 7,328 1,065 445 (723) (72) 2,773 Income from continuing operations 3,512 15,187 3,405 3,737 1,437 1,424 5,762 Gain (loss) on sale of discontinued operations, net of income taxes (312) 430 --- --- 306 231 159 Income before cumulative effect of change in accounting principle 3,200 15,617 3,405 3,737 1,743 1,655 5,921 Cumulative effect of change in accounting principle --- --- 300 --- --- --- --- Net income $3,200 $15,617 $3,705 $3,737 $1,743 $1,655 $5,921 Net income (loss) per common share: Income from continuing operations $0.49 $2.10 $0.39 $0.43 $0.17 $0.16 $0.66 Gain (loss) on sale of discontinued operations (0.04) 0.06 --- --- 0.03 0.03 0.02 Cumulative effect of change in accounting principle --- --- 0.03 --- --- --- --- Net income per share $0.45 $2.16 $0.42 $0.43 $0.20 $0.19 $0.68 Cash dividends per share $0.16 $0.16 $0.16 $0.16 $0.16 $0.12 $0.12 Weighted average common shares outstanding 7,172 7,233 8,763 8,763 8,760 8,760 8,759 Other Financial Data: EBITDA (3) $11,972 $29,519 $13,307 $14,841 $11,837 $ 9,050 $18,859 Net cash provided by operating activities 11,740 26,989 19,675 20,271 17,713 11,755 17,110 Capital and exploration expenditures(4) 23,767 19,793 22,787 30,934 32,419 23,591 36,680 Balance Sheet Data (end of period): Working capital 5,709 17,913 15,187 9,444 3,102 2,982 7,602 Net property and equipment 39,306 46,998 51,381 59,655 71,645 70,279 92,804 Total assets 53,781 75,896 81,797 89,392 96,126 91,144 132,680 Long-term debt 15,775 5,000 7,400 11,130 19,602 14,766 36,324 Total stockholders' equity 31,117 61,362 63,635 66,034 66,282 66,531 71,140 (1) In March 1995, the FASB issued 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. (2) Includes compensation expense recognized under the Company's SAR plan of $222,191, $268,286 and $220,247 in 1993, 1994 and 1995, respectively, and $243,000 and $604,000 during the nine months ended September 30, 1995 and 1996, respectively. In November 1996, the Company replaced the SAR plan with a stock option plan, and accordingly the SAR expense will be significantly lower in 1997. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Accounting Matters." (3) EBITDA is defined as income before income taxes, interest, 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. (4) Excludes certain international exploration costs. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital and Exploration Expenditures." 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 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 its Russian Partnership Interest. The Company accounts for its Russian Partnership Interest and investment in Summo Minerals under the equity method and includes its share of the income or loss from these entities. The Company has recently agreed to monetize its Russian Partnership Interest. The Company uses the successful efforts method to account for its investment in oil and gas properties whereby costs of productive wells, developmental dry holes and productive leases are capitalized and amortized using the unit-of-production method based on estimated net proved reserves. The costs of development wells are capitalized, whether productive or nonproductive. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined to be unsuccessful. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. 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 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. As of January 15, 1997, the Company had 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 barrel. The Company has also purchased options resulting in price collars and price floors on an additional 16% of the Company's estimated 1997 oil production with price ceilings between $23 and $27 per Bbl and price floors between $18 and $21 per Bbl. Results of Operations The following table sets forth selected operating data for the periods and upon the basis indicated: Nine Months Ended Year Ended December 31, September 30, 1993 1994 1995 1995 1996 Operating Data(1): Net Production: Oil (MBbl) 846 937 1,044 764 865 Gas (MMcf) 11,147 12,577 12,434 8,961 11,249 MBOE 2,704 3,033 3,116 2,258 2,739 Average sales price (2): Oil (per Bbl) $16.17 $14.95 $16.35 $16.33 $18.27 Gas (per Mcf) $ 2.20 $ 1.93 $ 1.56 $ 1.49 $ 2.12 Additional per BOE data: Lease operating expenses $ 2.42 $ 2.54 $ 2.49 $ 2.51 $ 2.28 Production taxes $ 1.04 $ 0.92 $ 0.93 $ 0.89 $ 1.10 Depletion, depreciation and amortization $ 3.25 $ 3.34 $ 3.28 $ 3.18 $ 3.34 (1) Excludes operating data attributable to the Company's Russian Partnership Interest. (2) Includes the effects of the Company's hedging activities. Nine Months Ended September 30, 1996 Compared With Nine Months Ended September 30, 1995 Oil and Gas Production Revenues. Oil and gas production revenues increased $13.8 million, or 53% to $39.7 million for the nine months ended September 30, 1996 compared with $25.9 million in the 1995 period. Oil production volumes increased 13% while gas production increased 26% for the first nine months of 1996 compared with the 1995 period. Average net daily production was 10.0 MBOE for the nine months ended September 30, 1996 compared to 8.3 MBOE in the 1995 period. This production increase resulted from new properties acquired and drilled during the past year. The average oil price for the nine months ended September 30, 1996 increased 12% to $18.27 per Bbl, while gas prices increased 42% to $2.12 per Mcf, from their respective 1995 levels. The Company hedged approximately 68% of its 1996 oil production at an average NYMEX price of $19.17 per barrel and 18% of its 1996 gas production at an average $1.91 per MMBtu. During the nine months ended September 30, 1996, the Company incurred total hedging losses of $1,493,000, including oil hedge losses of $846,000, or $0.98 per barrel, and gas hedge losses of $647,000, or $0.06 per Mcf. Oil and Gas Production Costs. Oil and gas production costs consist of lease operating expense and production taxes. Total production costs increased $1.6 million or 21% to $9.3 million for the nine months ended September 30, 1996 compared with the 1995 period. The lease operating expense per BOE was $2.28 for the nine months ended September 30, 1996 compared with $2.51 for the first nine months of 1995 primarily due to higher south Louisiana royalty production volume in 1996 and lower 1995 sales volumes stemming from low gas prices. Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion and amortization expense ("DD&A") increased $1.9 million or 27% to $9.1 million for the nine months ended September 30, 1996 compared with $7.2 million for the same period in 1995 due to increased production from new drilling and reserve acquisitions. DD&A per BOE was $3.34 in 1996 compared to $3.18 for the same period in 1995 because of the higher unit rate on reserve acquisitions. There was no impairment of proved properties for the nine months ended September 30, 1996 compared to $1.7 million for the same period in 1995 due to high cost marginal wells and low natural gas prices. Abandonment and impairment expenses for unproved properties was $1.2 million for the nine months ended September 30, 1996 compared with $759,000 for the respective 1995 period. Exploration. Exploration expense increased $2.0 million or 54% to $5.7 million for the nine months ended September 30, 1996 compared with $3.7 million in the 1995 period as a result of higher exploratory dry hole expense from increased drilling activity and a large 3-D seismic survey conducted in 1996. General and Administrative. General and administrative expense increased $937,000 or 23% to $5.1 million for the nine months ended September 30, 1996 compared to $4.1 million in 1995 because of higher compensation costs, professional fees and a $361,000 increase in the expense associated with the Company's SAR Plan. In the fourth quarter of 1996, the Company expects to recognize an additional expense of approximately $1 million associated with the SAR plan. On November 21, 1996, the Company exercised its right to terminate the SAR plan and adopted in lieu thereof a stock option plan and, accordingly, SAR expense will be substantially lower in 1997. Gas Contract Settlements and Other. Costs related to gas contract settlement and other, including legal expenses associated with gas contract disputes, declined $73,000 or 40% to $111,000 for the nine months ended September 30, 1996 compared to $184,000 for the 1995 period because all remaining legal disputes related to gas contracts with purchasers were settled in 1995. Loss in Equity Investees. The Company's share of net income from the Russian Partnership Interest was $405,000 for the nine months ended September 30, 1996 compared to a net loss of $94,000 for the comparable 1995 period because production and product prices increased significantly in 1996 from the 1995 levels. The Company's share of the net loss for Summo Minerals was $358,000 for the nine months ended September 30, 1996 compared to a net loss of $192,000 for the comparable 1995 period because of higher general and administrative costs arising from Summo Minerals' addition of personnel in anticipation of project financing and the commencement of mine development in 1997. See "Business and Properties -- Other Activities." Non-Operating Expense. Net interest expense increased $666,000 or 130% to $1.2 million for the nine months ended September 30, 1996 compared to $514,000 for the same period in 1995 because of the higher debt incurred for acquisitions and increased drilling activity. Income Taxes. The effective tax rate for the nine months ended September 30, 1996 increased to 34% compared to a 5% tax benefit in the 1995 period. The effective tax rate in 1995 resulted from the use of capital loss carryovers and Section 29 tax credits. Net Income. Net income for the nine months ended September 30, 1996 increased $4.3 million or 258% to $5.9 million compared to $1.7 million in 1995 because of higher production volumes and prices resulting in a $7.2 million increase in oil and gas production revenues, partially offset by the associated higher production expenses and DD&A, a $2.0 million increase in exploration expense and a $937,000 increase in general and administrative expenses. The 1995 net income also included a pre-tax gain of $1.1 million on the sale of producing properties. Comparison of Years Ended December 31, 1995, 1994 and 1993 Oil and Gas Production Revenues. 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 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 8,514 BOE in 1995 compared to 8,310 BOE in 1994. This production increase resulted from new properties acquired and drilled during 1995. The average realized oil price for 1995 increased 9% to $16.35 per barrel, while realized gas prices declined 19% to $1.56 per Mcf, from their respective 1994 levels. The Company hedged approximately 50% of its oil production for 1995 or 604,700 Bbls at an average NYMEX price of $17.66 and approximately 41% of its 1996 gross production at an average $18.34 NYMEX price. The Company realized a $131,000 decrease in oil revenue or $.13 per barrel for 1995 on these contracts compared to a $67,000 decrease or $.07 per barrel 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 revenue was unchanged at $38.2 million in 1994 and 1993. Oil and gas production volumes increased 11% and 13%, respectively, for the year ended December 31, 1994 compared with the 1993 period. Average net daily production reached 8,310 BOE in 1994 compared to 7,408 BOE in 1993. This production increase resulted from new properties acquired and drilled during 1994 and 1993. However, 1994 averaged realized oil prices declined 8% to $14.95 per barrel, while averaged realized gas prices declined 12% to $1.93 per Mcf, from their respective 1993 levels. Oil and Gas Production Costs. 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. Oil and gas production costs increased $1.2 million, or 12% to $10.5 million in 1994 compared with $9.3 million in 1993, due to additional operating costs on reserves purchased and new wells drilled. However, total oil and gas production costs per BOE were $3.46 in 1994, unchanged from 1993. Depreciation, Depletion, Amortization and Impairment. DD&A 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 resulting in an additional impairment charge for proved properties of $1.0 million in the fourth quarter of 1995. DD&A expense increased $1.3 million or 15% to $10.1 million in 1994 compared with $8.8 million in 1993 because of increased production from reserve acquisitions and drilling activity. DD&A expense per BOE increased 3% to $3.34 in 1994 compared to $3.25 in 1993. Impairment of proved oil and gas properties increased $721,000 or 21% to $4.2 million in 1994 compared with $3.5 million in 1993 because low year-end gas prices and several high cost marginal wells in newer fields required ceiling test writedowns. Abandonment and impairment of unproved properties increased $1.4 million or 141% to $2.4 million in 1995 compared to $1.0 million in 1994. The Company impaired $1.0 million of leasehold costs in 1995 as a result of several unsuccessful prospects in its drilling program. Abandonment and impairment expenses for unproved properties were $1 million in 1994 and 1993. Exploration. Exploration expense decreased $3.0 million or 37% to $5.1 million in 1995 compared to $8.1 million in 1994 because of reduced 1995 geophysical activity and better exploratory drilling results in 1995 compared with 1994. Exploration expense increased $2.6 million or 49% to $8.1 million in 1994 compared to $5.5 million in 1993 because of geophysical costs on 3-D seismic projects initiated in 1994 and higher exploratory dry hole costs associated with the Company's increased drilling activity. General and Administrative. 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. General and administrative expenses increased $549,000 or 12% in 1994 to $5.3 million compared to $4.7 million in 1993, primarily because of compensation expense associated with the Company's SARs, directors' and officers' insurance expense and additional overhead due to the large number of properties added from acquisitions and drilling in 1994 and 1993. Gas Contract Settlements and Other. Legal expenses in connection with gas contract disputes and the Company's mining activities declined $341,000 or 69% to $152,000 in 1995 compared with $493,000 in 1994 because all of the Company's mining activities are now conducted through the Company's equity investee, Summo Minerals. This expense declined $145,000 or 23% to $493,000 in 1994 from $638,000 in 1993 because of lower legal expense due to the resolution of the remaining gas contract disputes. Loss in Equity Investees. The equity in the net loss of the Russian Partnership Interest was $322,000 in 1995, $328,000 in 1994 and $659,000 in 1993. The equity in the net loss of Summo Minerals was $257,000 for 1995 and $20,000 in 1994 because of Summo Minerals' higher general and administrative expenses due to expansion of its Denver office in 1995. Non-Operating Expense. Net interest and other non-operating expense increased $371,000 or 71% to $896,000 in 1995 compared to $525,000 in 1994 because of additional interest expense associated with higher debt levels and the Company's increased ownership interest in Panterra. Net interest and other non-operating expense increased $463,000 or 747% to $525,000 in 1994 compared to $62,000 in 1993 because interest income declined on lower cash investments and the additional ownership in Panterra caused interest expense to increase. Income Taxes. Income taxes provided a net tax benefit of $723,000 for 1995 with the utilization of capital loss carryovers and Section 29 tax credits compared with income tax expense of $445,000 for 1994. The effective tax rate for 1994 declined to 11% compared to 24% in 1993 because of higher Section 29 tax credits in 1994. State tax expense was $396,000 in 1995, $445,000 in 1994 and $587,000 in 1993, primarily due to lower Louisiana income taxes in 1995 and 1994. The Company also recognized a $300,000 tax benefit for the cumulative effect of adopting SFAS No. 109, "Accounting for Income Taxes" as of January 1, 1993. Net Income. Net income for 1995 declined $2.0 million or 53% to $1.7 million compared to $3.7 million in 1994. The Company results in 1995 included a $1.3 million gain from the sale of producing properties and $800,000 of other non-production revenue while settlements of gas contracts and other non-production income added $6.5 million to revenues in 1994. Lower 1995 natural gas prices and associated revenue were more than offset by reduced exploration 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. Net income for 1994 was $3.7 million, unchanged from 1993. Higher production in 1994 was offset by lower product prices and $5.7 million of gas contract revenue was offset by higher DD&A and impairment of producing properties, higher exploration costs due to 3-D seismic and exploratory drilling, increased general and administrative and interest expense, when compared to 1993. Liquidity and Capital Resources The Company's primary sources of liquidity are cash provided by operating activities and borrowings under its 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 $5.4 million or 46% to $17.1 million for the nine months ended September 30, 1996 compared with $11.8 million in the 1995 period primarily due to increased revenue from oil and gas sales. Net cash used in investing activities increased $6.8 million or 29% to $30.1 million for the nine months ended September 30, 1996 compared to $23.3 million in the 1995 period. Increased capital expenditures from the Company's expanded drilling programs and oil and gas property acquisitions accounted for the increase. Net cash provided by financing activities was $15.7 million for the nine months ended September 30, 1996 consisting of net debt proceeds for acquisitions and drilling activities, partially offset by dividends compared with net cash provided of $2.5 million in the 1995 period. In the first quarter of 1997, the Company will make 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. 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. The Company's net cash provided by operating activities increased 3% to $2.3 million in 1994 compared to $19.7 million in 1993. Gas contract settlements received in 1994 were partially offset by higher operating and exploration costs. 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, 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 $22.0 million in 1994 due to increased drilling activity and reserve acquisitions. The Company invested $4.5 million in Summo Minerals during 1995 increasing its ownership to 51%. Net cash used in investing activities increased 13% to $23.1 million in 1994 compared with $20.5 million in 1993 primarily due to increased capital expenditures partially offset by a decline in contributions to the Russian joint venture. Total capital expenditures, including acquisitions of oil and gas properties, in 1994 were $22.0 million compared to $18.3 million in 1993 because of increased drilling activity and property acquisitions. Net cash provided by financing activities was $7.0 million in 1995 compared to net cash used by financing activities of $2.0 million in 1994. The Company borrowed funds in 1995 for its capital expenditure programs and mining investment compared with debt repayment of $578,000 in 1994. Net cash used by financing activities was $2.0 million in 1994 compared to net cash provided by financing activities of $4.9 million in 1993. The Company used funds to repay debt in 1994 while it borrowed funds in 1993 to finance a portion of the reserve acquisitions. The Company also received proceeds from its common stock offering in 1993. The Company paid dividends of $1.4 million in 1995, 1994 and 1993. Credit Facility. On April 1, 1996, the Company amended and restated its Credit Facility with two banks to provide a $60 million secured 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, is currently $40 million and is expected to increase for 1997 based on the increase in the Company's estimated net proved reserves in 1996. See "Business and Properties -- Estimated Net Proved Reserves." Outstanding revolving loan balances under the Company's Credit Facility 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 Common Stock. Panterra, in which the Company has a 74% general partnership ownership interest, has a separate credit facility with an $18.5 million borrowing base and $13.1 million outstanding as of December 31, 1996. St. Mary guarantees its pro rata share of the Panterra Credit Facility. The Panterra Credit Facility expires on February 1, 2002. During January 1997, Panterra expects to amend its Panterra Credit Facility to provide for a $26 million borrowing base. 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(1) (dollars in thousands) Nine Months Year Ended December 31, Ended September 30, 1993 1994 1995 1995 1996 Development $ 7,079 $ 5,946 $12,625 $7,998 $13,406 Exploration 9,013 9,481 8,746 6,142 7,269 Acquisitions: Proved 4,848 12,279 8,111 5,711 13,567 Unproved 1,847 4,228 2,937 3,740 2,438 Total $22,787 $30,934 $32,419 $23,591 $36,680 (1) Excludes certain international exploration costs. The Company's total costs incurred for the nine months ended September 30, 1996 increased 55% to $36.7 million compared to $23.6 million for the comparable 1995 period. Proved property acquisitions increased $7.9 million to $13.6 million for the nine months ended September 30, 1996 compared to $5.7 million for the 1995 period. The Company spent $23.1 million for domestic exploration and development and unproved property acquisitions for the nine months ended September 30, 1996 compared to $17.9 million for the 1995 period. The Company's total costs incurred in 1995 increased 5% to $32.4 million compared to $30.9 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 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. The Company's total costs incurred in 1994 increased 36% to $30.9 million compared to $22.8 million in 1993. Proved property acquisitions increased $7.5 million to $12.3 million in 1994 compared to $4.8 million in 1993. The Company spent $18.7 million in 1994 for unproved property acquisitions and domestic exploration and development compared to $17.9 million in 1993. For 1997, the Company anticipates spending approximately $65 million for capital and exploration expenditures with $43 million allocated for domestic exploration and development, $15 million allocated for domestic property acquisitions and $7 million for large-target, high-risk domestic exploration and development. See "Use of Proceeds." 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. Accounting Matters The Company adopted SFAS No. 109, "Accounting for Income Taxes" as of January 1, 1993 and recorded a $300,000 benefit in the results of operations for the cumulative effect of a change in accounting principle. As of January 1, 1994, the Company adopted SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," which provides for reporting of certain debt and equity securities at fair value and the inclusion of unrealized holding gains and losses in earnings or stockholders' equity. 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 of $1 million in the fourth quarter of 1995. In November 1996, the Company adopted a stock option plan which covers a maximum of 700,000 shares. Options granted under the 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 will 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 will adopt SFAS No. 123, "Accounting for Stock-Based Compensation," in its annual report on Form 10-K 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 262,372 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. The new stock option plan is subject to shareholder approval. Effects of Inflation and Changing Prices The Company's results of operations and cash flow are affected by changing oil and gas prices. 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. BUSINESS AND PROPERTIES General St. Mary Land & Exploration 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 net estimated proved reserves of 28.5 MMBOE at an average Finding Cost of approximately $4.15 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 $3.50 per BOE. In 1996 the Company's estimated net proved reserve additions replaced 424% of production, including 247% from drilling, 124% from property acquisitions and 53% from revisions. The Company's 1997 capital budget of $65 million includes (i) $43 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 million for niche acquisitions of properties and (iii) $7 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 3-D 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 spent $31 million on development and exploration, including participation in 117 successful gross wells reflecting an overall 82% success rate. 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 seven 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 is presently being completed. 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 totalling $41.5 million at an average acquisition cost of $3.89 per BOE. Strategic Relationships. Throughout its 89-year history the Company has cultivated strategic partnerships with independent oil and gas operators having specialized experience and technical skills. The Company's strategy is to serve as operator or alternatively to maintain a majority interest in such ventures to ensure that it can exercise significant influence over development and exploration activities. In addition the Company seeks industry partners who are willing to co-invest on substantially the same basis as the Company. For example, the Company's operations in the Williston Basin are conducted through Panterra in which St. Mary holds a 74% general partnership interest. The managing partner of Panterra is Nance Petroleum Corporation, the principal of which has over 25 years of experience in the Williston Basin. Properties - Principal Areas of Operations The Company's exploration, development and acquisition activities are focused in five core operating areas: the Mid-Continent region; the ArkLaTex region; south Louisiana; the Williston Basin in North Dakota and Montana; and the Permian Basin in west Texas and New Mexico. Set forth below is information concerning each of the Company's major areas of operations based on the Company's estimated net proved reserves as of December 31, 1996. Oil Gas MBOE PV-10 Value (MBbls)(MMcf) Amount Percent ($/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 South Louisiana 230 7,386 1,461 4.6 19,424 6.6 Williston Basin 5,648 3,734 6,270 19.7 46,006 15.5 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 2.8 Total 10,691 127,057 31,687 100.0% $296,461 100.0% (1) Excludes amounts attributable to the Company's Russian Partnership Interest. The Company has agreed to monetize the Russian Partnership Interest, and the closing is expected to occur in the first quarter of 1997. See "-Other Activities." 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% 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. 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 Lower and Upper Morrow formations in Beckham and Roger Mills Counties, Oklahoma. These prospects target potential 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 additional 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 discoveries in the Ordovician Oil Creek sands during 1994 and 1995. In 1997, the Company plans to conduct a 21 square mile 3-D seismic survey and to continue further exploration in its Red Branch prospect area where it has an average 43% 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% 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 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 early 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 as well as rights to over 6,000 miles of proprietary seismic data covering 30 counties in east Texas. 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 6 wells during 1995 to participation in 15 wells and 30 workovers and recompletions during 1996, including 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. 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 deep Smackover formation at a depth of approximately 10,500 feet. Since acquiring this Field, St. Mary has increased production from the deep 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 and 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, four completed in the Cotton Valley formation and one 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 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 15,970 acres are leased or subject to lease options and 9,000 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 1992 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 7 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 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% royalty interest and a 25% working interest, resulting in an approximate 41% net revenue interest in this 3-D seismic-defined test of the Operc sands at a depth of approximately 17,300 feet. 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 is expected to spud in early 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 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 which 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 the first quarter 1997 and plans to test multiple potential pays, including the Frio and Hackberry sands, on an untested fault block near the top of the structure. 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% 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 zones, including the Marge A formation, 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." 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 totaled approximately $26 million and 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 features together with porosity development 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 lead 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 BOPD in 1991 to over 2,000 BOPD 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. 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 prospects and potential for water flood 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 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 and Gas Company 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 and adjacent areas 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 MBBbls 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." Siete Properties. In 1996 the Company completed the acquisition of a 90% interest in the oil and gas properties of Siete Oil and Gas Company for $10.0 million. The acquisition included approximately 150 wells in southeast New Mexico and west Texas producing from the Yates/Queen and Delaware sands at depths of between 3,500 and 5,000 feet and which are operated by the Company's 10% partner. The acquired reserves were 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 $1.2 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 possible 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. See "Risk Factors -- Substantial Capital Requirements." The following table summarizes the Company's active large-target exploration projects. See also "--Properties-Principal Areas of Operations." St. Mary St. Mary Expected Project Working Royalty Drilling Name Objective Location Interest(1)Interest(2) Date(3) South Horseshoe Bayou Operc, St. Mary 25.0% 22.0% early 1997 19,000' Parish, LA Mustang Sale Marge A, St. Mary - 12.5% mid 1997 15,000' Parish, LA Roanoke Frio, Jefferson 33.3% - early 1997 (4) Hackeberry Davis Parish, LA Red Oil Creek/ Grayson & 37.5% - 1997-1998 Branch Penn Cooke Coun- (4) ties, TX Patterson Marge A St. Mary 25.0% - 1998 (4) Parish, LA Carrier Cotton Leon County, 24.0% - 1998-1999 (4) Valley TX Reef Ward Siluro Ward & Winkler 21.0% - 2000 Estes Devonian Counties, TX and Ellenburger (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. 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 million in 1997 for property acquisitions. See "Risk Factors - Acquisition Risks." Estimated Net Proved 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 text of the Ryder Scott report is attached as Exhibit A to this Prospectus. 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. 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, 1994 1995 1996 Reserve Data: (1) Oil (MBbls). . . . . . . . . . . 6,677 7,509 10,691 Gas (MMcf) . . . . . . . . . . . 62,515 75,705 127,057 MBOE . . . . . . . . . . . . . . 17,096 20,127 31,867 PV-10 Value (in thousands) . . . $84,688 $120,192 $296,461 Proved developed reserves (%). . 93% 89% 84% Production replacement (%) . . . 207% 203% 424% Reserve Life (years) . . . . . . 6.1 6.5 7.2 (1 For limitations on the accuracy and reliability of estimated net proved reserves and future net revenue estimates, see "Risk Factors - Uncertainty of Estimates of Reserves and Future Net Revenues." Reserve data attributable to the Company's Russian Partnership Interest have been excluded from this table. The Company has agreed to sell its Russian Partnership Interest and the closing is expected to occur in the first quarter of 1997. See "--Other Activities." Production, Price and Cost History The following table summarizes the average net daily volumes of oil and gas produced from all domestic properties in which the Company held an interest during the periods indicated. Nine Months Ended Year Ended December 31, September 30, 1993 1994 1995 1995 1996 Operating Data:(1) Net production: Oil (MBbls) 846 937 1,044 764 865 Gas (MMcf) 11,147 12,577 12,434 8,961 11,249 MBOE 2,704 3,033 3,116 2,258 2,739 Average net daily production: Oil (Bbls) 2,319 2,567 2,852 2,798 3,156 Gas (Mcf) 30,539 34,458 33,973 32,824 41,053 BOE 7,408 8,310 8,514 8,270 9,998 Average realized sales price:(2) Oil (per Bbl) $16.17 $14.95 $16.35 $16.33 $18.27 Gas (per Mcf) $ 2.20 $ 1.93 $ 1.56 $ 1.49 $ 2.12 Additional per BOE data: Lease operating expense $ 2.42 $ 2.54 $ 2.49 $ 2.51 $ 2.28 Production taxes $ 1.04 $ 0.92 $ 0.93 $ 0.89 $ 1.10 (1) Excludes operating data attributable to the Company's Russian Partnership Interest. (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. 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. Gross Net Oil. . . . . 529 136 Gas. . . . . 884 105 Total. . . . 1,413 241 Drilling Activity The following table sets forth the wells drilled by the Company during each of the three years indicated. Year Ended December 31, 1994 1995 1996 Gross Net Gross Net Gross Net Development: Oil 4 1.07 6 1.52 17 3.91 Gas 30 4.91 38 7.75 74 13.29 Non- productive 3 0.33 6 2.00 11 2.70 Total 37 6.31 50 11.27 102 19.90 Exploratory: Oil 1 0.25 5 1.56 - - Gas 14 2.26 8 0.74 5 1.25 Non- productive 19 3.82 16 4.19 10 3.10 Total 34 6.33 29 6.49 15 4.35 Farmout or Non- consent 7 - 4 - 9 - Grand Total(1) 78 12.64 83 17.76 126 24.25 (1) Does not include 6, 4 and 3 gross wells completed on the Company's fee lands during 1994, 1995 and 1996, respectively. All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment. Leasehold and Other Interests 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 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(3) 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 Grand Total 274,612 81,190 377,292 145,619 651,904 226,809 (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 minor interests in Canada and Trinidad and Tobago. Other Activities Summo Minerals. Since 1994, St. Mary Minerals Inc.("St. Mary Minerals"), a wholly-owned subsidiary of the Company, has invested a total of approximately $5.9 million and has acquired a total of 9,924,093 common shares of Summo Minerals representing 49.9% of the issued and outstanding common shares and 5,831,090 warrants to purchase common shares, exercisable at prices between $1.10 and $1.38 Cdn and which expire between February 2, 1997 and October 31, 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". 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 does not plan to participate in such financing. If Summo Minerals is not successful in arranging such financing, the Company currently expects to invest no more than approximately $1.0 to $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. Russian Partnership Interest. Chelsea Corporation ("Chelsea"), a wholly-owned, second tier subsidiary of the Company, owns a 36% interest (the "Russian Partnership Interest") in the Anderman/Smith International - Chernogorskoye Partnership which in turn owns a 50% interest 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 Partnership Interest to Ural Petroleum Corporation ("UPC"). Closing of the transaction, which is subject to certain conditions, including the completion of financing, is expected to occur in early 1997. In accordance with the terms of the acquisition agreement, Chelsea will receive cash consideration of approximately $5.2 million, approximately $1.7 million of UPC common stock and a receivable in the form of retained production payment of approximately $10.3 million plus interest at 10% per annum from the limited liability company formed to hold the Russian Partnership Interest. Chelsea's retained production payment will be collateralized by the Russian Partnership Interest. Chelsea has the right, subject to certain conditions, to require UPC to purchase Chelsea's retained production payment 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 retained production payment into UPC common stock immediately prior to an initial public offering of UPC common stock. 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. 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. 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. MANAGEMENT Directors and Executive Officers The following table sets forth the names, ages and positions of the executive officers and the members of the Board of Directors of the Company. All directors are elected for a term of one year and serve until their successors are elected and qualified. Name Age Position Thomas E. Congdon (1) 70 Chairman of the Board of Directors and Director Mark A. Hellerstein 44 President, Chief Executive Officer and Director Ronald D. Boone 49 Executive Vice President, Chief Operating Officer and Director Ralph H. Smith 54 Senior Vice President David L. Henry 40 Vice President and Chief Financial Officer Larry W. Bickle (3) 51 Director David C. Dudley (1) 46 Director Richard C. Kraus (2) 50 Director R. James Nicholson(2)(3) 59 Director Arend J. Sandbulte (1)(2) 63 Director John M. Seidl (3) 58 Director (1) Member of Executive Committee (2) Member of Compensation Committee (3) Member of Audit Committee The Audit Committee's functions include recommending to the Board of Directors the engagement of the Company's independent public accountants, reviewing with such accountants the plans for and the results and scope of their auditing engagement and certain other matters relating to their services provided to the Company, including the independence of such accountants. The Compensation Committee reviews on behalf of, and makes recommendations to, the Board of Directors with respect to compensation of directors, executive officers and key employees. Thomas E. Congdon. Mr. Congdon has served the Company as an officer and director since 1966, including service as its President and Chief Executive Officer for more than 25 years. Mr. Congdon is also a director, officer or general partner of a number of family corporations and partnerships which produce scientific and statistical software, iron ore and agricultural products, manage marketable securities and own and operate developed real estate. From 1980 to 1991, he was Chairman of the Board of Directors of CoCa Mines Inc., which was an affiliate of the Company during that time. From 1974 to 1994, he was a director of Colorado National Bankshares Inc., a bank holding company. Mark A. Hellerstein. Mr. Hellerstein joined the Company in September 1991 and served as Executive Vice President and Chief Financial Officer until May 1992, at which time he was elected President and a director of the Company. Mr. Hellerstein was elected Chief Executive Officer of the Company in May 1995. He also has served as Chairman of the Board of Summo Minerals since 1995. From 1987 through August 1991 (excluding October 1989 to May 1990), he served as Vice President-Finance, Chief Financial Officer and Secretary for CoCa Mines Inc. Ronald D. Boone. Mr. Boone has served the Company as Executive Vice President since 1990, as Chief Operating Officer since 1992 and as a director of the Company since 1996. From 1981 to 1990, he was employed in various capacities by Anderman/Smith Operating Company, an affiliate of the Company during that period, most recently as Vice President-Production and Engineering. Ralph H. Smith. Mr. Smith has served the Company as Senior Vice President - Mid Continent since 1995. From 1982 to 1994, he was Executive Vice President of Anderman/Smith Operating Company, an affiliate of the Company during that period. In addition, he has been a director and President of R.H. Smith International Corporation since 1989. David L. Henry. Mr. Henry joined the Company in 1996 as Vice President and Chief Financial Officer. From 1983 to 1996, he was employed in corporate finance investment banking positions with Boettcher & Company, Inc., CharterWest Capital Co. and most recently as Director-Corporate Finance for Hanifen, Imhoff Inc. Larry W. Bickle. Mr. Bickle has served as a director of the Company since 1995. He currently is Chairman and Chief Executive Officer of TPC Corporation, a public gas storage and transportation company he co-founded in 1984. David C. Dudley. Mr. Dudley has served as a director of the Company since 1986. Since 1983, he has served as Managing Partner of Dudley & Associates, LLC, Denver, Colorado, a closely-held oil and gas exploration and production firm. Since 1985, he has served as general partner of the New York investment advisory firm Dudley & Company. In addition, since 1980 Mr. Dudley has served as a general partner of Greenhouse Associates, a closely-held investment partnership. Richard C. Kraus. Mr. Kraus has served as a director of the Company since 1994. Since 1981, he has been employed by Echo Bay Mines Ltd., a public company engaged primarily in mining operations, and currently serves as its President and Chief Executive Officer. In addition, he has been an Echo Bay director since 1992. R. James Nicholson. Mr. Nicholson has served as a director of the Company since 1987. Since 1978, he has served as President of Nicholson Enterprises, Inc., a land development company. Mr. Nicholson has also served as President of Renaissance Homes, a residential home building company, since 1988. Since 1974, he has served as a director of Lerch, Bates & Associates, Inc., a consulting engineering firm. He was elected Chairman of the Republican National Committee in January 1997. Arend J. Sandbulte. Mr. Sandbulte has served as a director of the Company since 1989. From 1964 to 1996, he was employed by Minnesota Power & Light Company, a publicly-held energy utility, most recently as its Chairman of the Board, President and Chief Executive Officer. Mr. Sandbulte has served as a director of Utech Venture Capital Corp., a joint research venture of ten utilities, since 1989. John M. Seidl. Mr. Seidl has served as a director of the Company since 1994. He currently serves as President and Chief Executive Officer of CellNet Data Systems. From 1989 to 1993, he served as an officer and director of MAXXAM Inc. and Kaiser Aluminum Corporation and The Pacific Lumber Company, subsidiaries of MAXXAM Inc., a public company. There are no family relationships (first cousin or closer) among the directors. There are no arrangements or understandings between any director and any other person pursuant to which that director was elected. DESCRIPTION OF COMMON STOCK The Company's authorized capital consists of 15,000,000 shares of Common Stock, par value $.01 per share. Upon completion of this offering, the Company will have 10,759,214 shares of Common Stock outstanding. Holders of Common Stock are entitled to one vote for each share held in the election of directors and on all other matters submitted to a vote of stockholders and do not have cumulative voting rights. Holders of a majority of the shares of Common Stock entitled to vote in any election of directors may elect all of the directors standing for election. Holders of Common Stock are entitled to receive ratably such dividends, if any, as may be declared by the Board of Directors out of funds legally available therefor. See "Dividend Policy." Upon the liquidation, dissolution or winding up of the Company, the holders of Common Stock are entitled to receive ratably the net assets of the Company available after payment of all debts and other liabilities. Holders of Common Stock have no preemptive, subscription, redemption or conversion rights. The outstanding shares of Common Stock are, and the shares offered by the Company in this offering will be, when issued and paid for, fully paid and non-assessable. Certain Limited Liability and Indemnification Provisions As permitted by the provisions of the Delaware General Corporation Law, the Certificate of Incorporation eliminates in certain circumstances the monetary liability of directors of the Company for a breach of their fiduciary duty as directors. These provisions do not eliminate the liability of a director (i) for a breach of the director's duty of loyalty to the Company or its stockholders; (ii) for acts or omissions by a director not in good faith or which involve intentional misconduct or a knowing violation of law; (iii) for liability arising under Section 174 of the Delaware General Corporation Law (relating to the declaration of dividends and purchase or redemption of shares in violation of the Delaware General Corporation Law); or (iv) for any transaction from which the director derived an improper personal benefit. In addition, these provisions do not eliminate the liability of a director for violations of federal securities laws, nor do they limit the rights of the Company or its stockholders, in appropriate circumstances, to seek equitable remedies such as injunctive or other forms of non-monetary relief. Such remedies may not be effective in all cases. The Company's Certificate of Incorporation and Bylaws provide that the Company shall indemnify all directors and officers of the Company to the full extent permitted by the Delaware General Corporation Law. Under such provisions, any director or officer, who in his capacity as such is made or threatened to be made, a party to any suit or proceeding, may be indemnified if the Board determines such director or officer acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interest of the Company. The Certificate, Bylaws and the Delaware General Corporation Law further provide that such indemnification is not exclusive of any other rights to which such individuals may be entitled under the Certificate, the Bylaws, any agreement, vote of stockholders or disinterested directors or otherwise. Transfer Agent and Registrar The transfer agent and registrar for the Company's Common Stock is American Securities Transfer and Trust, Incorporated, Denver, Colorado. UNDERWRITING Subject to the terms and conditions of the Underwriting Agreement among the Company and the Underwriters named below (the "Underwriting Agreement"), the Company has agreed to sell to each of such Underwriters named below, and each of such Underwriters, for whom Morgan, Keegan & Company, Inc., A.G. Edwards & Sons, Inc. and Hanifen, Imhoff Inc. are acting as representatives, has severally agreed to purchase from the Company, the respective number of shares of Common Stock set forth opposite its name below. Underwriter Number of Shares Morgan Keegan & Company, Inc. . . . . . . . A.G. Edwards & Sons, Inc. . . . . . . . . . Hanifen, Imhoff Inc. . . . . . . . . . . . . Total . . . . . . . . . . 2,000,000 Under the terms and conditions of the Underwriting Agreement, the underwriters are committed to take and pay for all of the shares of Common Stock offered hereby, if any are taken. The Underwriters propose to offer the shares of Common Stock in part directly to the public at the initial public offering price set forth on the cover page of this Prospectus, and in part to certain securities dealers at such price less a concession of $_____ per share. The Underwriters may allow, and such dealers may allow, a concession not in excess of $_____ per share to certain brokers and dealers. After the shares of Common Stock are released for sale to the public, the offering price and other selling terms may from time to time be varied by the representatives. The Company has granted the Underwriters an option exercisable for 30 days after the date of this Prospectus to purchase up to an aggregate of 300,000 additional shares of Common Stock solely to cover over-allotments, if any. If the Underwriters exercise their over-allotment option, the Underwriters have severally agreed, subject to certain conditions, to purchase approximately the same percentage thereof that the number of shares of Common Stock to be purchased by each of them, as shown in the table above, bears to the 2,000,000 shares of Common Stock. The Company has agreed in the Underwriting Agreement not to offer, sell, contract to sell, grant any option to purchase or otherwise dispose of any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock, subject to certain limited exceptions, for a period of 120 days after the date of this Prospectus without the prior written consent of the representatives. In addition, the Company's directors and executive officers have agreed not to sell, contract to sell, grant any option to purchase or otherwise dispose of any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock, other than as gifts, pledges and certain other transfers to persons who agree to the same restrictions for a period of 120 days after the date of this Prospectus without the prior written consent of the representatives. In connection with this offering, certain Underwriters may engage in passive market making transactions in the Common Stock on the Nasdaq National Market immediately prior to the commencement of sales in this offering, in accordance with Rule 10b-6A under the Exchange Act. Passive market making consists of, among other things, displaying bids on the Nasdaq National Market limited by the bid prices of independent market makers and purchases limited by such prices and effected in response to order flow. Net purchases by a passive market maker on each day are limited to a specified percentage of the passive market maker's average daily trading volume in the Common Stock during a specified prior period, and all passive market making activity must be discontinued when such limit is reached. Passive market making may stabilize the market price of the Common Stock at a level above that which might otherwise prevail and, if commenced, may be discontinued at any time. The Company has agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act or to contribute to payments the Underwriters may be required to make in respect of such liabilities. LEGAL MATTERS Certain legal matters with respect to the Common Stock offered hereby have been passed upon for the Company by Cohen Brame & Smith Professional Corporation, Denver, Colorado. Certain legal matters will be passed upon for the Underwriters by Butler & Binion, L.L.P., Houston, Texas. EXPERTS The consolidated balance sheets as of December 31, 1995 and 1994 and the consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1995 included and incorporated by reference in this Prospectus have been included herein in reliance on the report of Coopers & Lybrand L.L.P., independent accountants, given on the authority of that firm as experts in accounting and auditing. The Statement of Revenues and Direct Operating Expenses of Certain Oil & Gas Properties Acquired from Siete Oil & Gas Corporation for the year ended December 31, 1995 incorporated by reference in this Prospectus have been included herein in reliance on the report of Coopers & Lybrand L.L.P., independent accountants, given on the authority of that firm as experts in accounting and auditing. Certain estimates of oil and gas reserves appearing herein were based upon engineering reports prepared by the independent petroleum engineering firm of Ryder Scott Company. Such estimates are included herein in reliance upon the authority of such firm as experts in such matters. AVAILABLE INFORMATION The Company is subject to the informational requirements of the Exchange Act and in accordance therewith files reports, proxy statements and other information with the Commission. Such reports, proxy statements and other information concerning the Company may be inspected and copied at the public reference facilities maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the Commission's Regional Offices at 500 West Madison Street, Suite 1400, Chicago, Illinois 60661 and at Seven World Trade Center, Thirteenth Floor, New York, New York 10048. Copies of such material can also be obtained upon written request addressed to the Commission, Public Reference Section, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. In addition, such material can be inspected at the offices of the National Association of Securities Dealers, Inc., 1735 K Street, Washington, DC 20006. Further, the Commission maintains a Website (http:\\www.sec.gov) that contains reports, proxy and information statements and other information filed by registrants electronically with the Commission through the Electronic Data Gathering, Analysis, and Retrieval system. The Company has filed with the Commission a registration statement on Form S-3 (herein, together with all amendments and exhibits, referred to as the "Registration Statement") under the Securities Act with respect to the Common Stock offered hereby. This Prospectus, which constitutes a part of the Registration Statement, does not contain all of the information set forth in the Registration Statement, certain parts of which are omitted in accordance with the rules and regulations of the Commission. For further information, reference is hereby made to the Registration Statement which may be inspected and copied in the manner and at the sources described above. With respect to each such agreement, instrument, or other document filed as an exhibit to the Registration Statement, reference is made to the exhibit for a more complete description of the matter involved, and each such statement shall be deemed qualified in its entirety by such reference. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents filed by the Company with the Commission pursuant to the Exchange Act (file number 0-20872) are incorporated herein by reference, except as superseded or modified herein: (i) The Company's Annual Report on Form 10-K for the year ended December 31, 1995; (ii) The Company's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 1996, June 30, 1996 and September 30, 1996,as amended by a Form 10-Q/A dated November 15, 1996; (iii)The Company's Current Report on Form 8-K dated June 28, 1996, as amended by a Form 8-K/A dated June 28, 1996, regarding the acquisition of an interest in certain of the assets of Siete Oil and Gas Company; (iv) The Company's Current Report on Form 8-K dated December 16, 1996 regarding the sale of the Company's Russian Partnership Interest; (v) The Company's Current Report on Form 8-K dated January 28, 1997 regarding certain exhibits; and (vi) The Company's Registration Statement on Form 8-A filed November 18,1992. All reports and other documents subsequently filed by the Company pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this Prospectus and prior to the termination of this offering shall be deemed to be incorporated by reference herein and to be a part hereof from the date of filing of such reports and documents. Any statement contained herein or in a document incorporated or deemed to be incorporated herein by reference shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained in this prospectus or in any subsequently filed document (which is deemed to be incorporated by reference herein) modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. To the extent the information relating to the Company contained in this Prospectus summarizes, is based upon or refers to, information and financial statements contained in one or more of the documents incorporated by reference herein, the information contained herein is qualified in its entirety by reference to such document, and it should be read in conjunction therewith. The Company will provide, without charge, to each person to whom a copy of this Prospectus is delivered, on the written or oral request of such person, a copy of any or all of the documents incorporated herein by reference (other than exhibits thereto, unless such exhibits are specifically incorporated by reference into the information that this Prospectus incorporates). Written or telephone requests for such copies should be directed to the Company's principal office: St. Mary Land & Exploration Company, 1776 Lincoln Street, Suite 1100, Denver, Colorado 80203, (303) 861- 8140. GLOSSARY The terms defined in this section are used throughout this Prospectus. 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. Fee Land. The most extensive interest which can be owned in land, including surface and mineral (including oil and gas) rights. Finding Costs. 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. MBOE. One thousand barrels of oil equivalent. Mcf. One thousand 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 from 59.5 to 60.5 degrees Fahrenheit under specified conditions. MMcf. One million cubic feet. 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 estimated production for the following 12-month period. 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. 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 a share of production. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Consolidated Interim Financial Statements (Unaudited) Consolidated Balance Sheets as of September 30, 1996 (Unaudited) and December 31, 1995 . . . . . . . . . . F-2 Consolidated Statements of Income for the nine month periods ended September 30, 1996 and 1995 (Unaudited) . . . . . . . . . . . . . F-3 Consolidated Statements of Cash Flows for the nine month periods ended September 30, 1996 and 1995 (Unaudited) . . . . . . . . . . . . . F-4 Notes to Consolidated Financial Statements (Unaudited). . . . . . . . F-6 Consolidated Annual Financial Statements Report of Independent Accountants . . F-8 Consolidated Balance Sheets as of December 31, 1995 and 1994. . . . . . F-9 Consolidated Statements of Income for each of the three years in the period ended December 31, 1995. . . . F-10 Consolidated Statements of Shareholders' Equity for each of the three years in the period ended December 31, 1995 F-11 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1995. . . . F-12 Notes to Consolidated Financial Statements. . . . . . . . . . . . . . F-14 ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, except share amounts) September 30, December 31, 1996 1995 ASSETS (Unaudited) Current assets: Cash and cash equivalents $ 4,405 $ 1,723 Accounts receivable 20,707 8,068 Prepaid expenses 2,146 850 Refundable income taxes 35 176 Total current assets 27,293 10,817 Property and equipment (successful efforts method), at cost: Proved oil and gas properties 191,670 165,750 Unproved oil and gas properties, net 15,306 11,752 Other 3,414 2,535 210,390 180,037 Less accumulated depletion, depreciation, amortization and impairment (117,586) (108,392) 92,804 71,645 Other assets: Investment in Russian joint venture 4,788 4,140 Investment in Summo Minerals Corporation 4,483 4,842 Other assets 3,312 4,682 12,583 13,664 $132,680 $ 96,126 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 19,691 $ 7,715 Long-term liabilities: Long-term debt 36,324 19,602 Deferred income taxes 3,427 1,228 Stock appreciation rights 1,782 1,178 Other noncurrent liabilities 316 121 41,849 22,129 Commitments and contingencies (Note 3) 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 85 88 Additional paid-in capital 15,803 15,835 Retained earnings 55,248 50,378 Unrealized gain on marketable equity securities - available for sale 4 15 Treasury stock - 2,572 shares, at cost - (34) Total stockholders' equity 71,140 66,282 $132,680 $ 96,126 The accompanying notes are an integral part of these consolidated financial statements. ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In thousands, except share amounts) (Unaudited) Nine months ended September 30, 1996 1995 Operating revenues: Oil and gas production $39,689 $25,860 Gain (loss) on sale of proved properties - 1,052 Gas contract settlements and other revenues 490 528 Total operating revenues 40,179 27,440 Operating expenses: Oil and gas production 9,262 7,676 Depletion, depreciation and amortization 9,144 7,184 Impairment of proved properties - 1,673 Exploration 5,688 3,683 Abandonment and impairment of unproved properties 1,240 759 General and administrative 5,066 4,129 Gas contract disputes and other 111 184 (Income) loss in equity investees (47) 286 Total operating expenses 30,464 25,574 Income from operations 9,715 1,866 Nonoperating income and (expense): Interest income 227 230 Interest expense (1,407) (744) Income from continuing operations before income taxes 8,535 1,352 Income tax expense (benefit) 2,773 (72) Income from continuing operations 5,762 1,424 Gain on sale of discontinued operations, net of taxes 159 231 Net income $ 5,921 $ 1,655 Net income per common share: Income from continuing operations $ .66 $ .16 Gain on sale of discontinued operations .02 .03 Net income per share $ .68 $ .19 Weighted average common shares outstanding 8,759 8,760 The accompanying notes are an integral part of these consolidated ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited) Nine months ended September 30, 1996 1995 Cash flows from operating activities: Cash received from oil and gas operations $32,034 $24,206 Cash paid for oil and gas operations, including general and administrative expenses (9,868) (9,323) Exploration expenses (4,035) (2,764) Interest and other receipts 381 393 Interest paid (1,300) (479) Income taxes paid (102) (278) Net cash provided by operating activities 17,110 11,755 Cash flows from investing activities: Proceeds from sale of oil and gas properties 146 2,227 Capital expenditures, including dry hole costs (20,017) (14,609) Acquisition of oil and gas properties (13,557) (9,005) Investment in St. Mary Operating Company 3,059 - Investment in Summo Minerals Corporation - (2,042) Other 271 167 Net cash used by investing activities (30,098) (23,262) Cash flows from financing activities: Proceeds from long-term debt 23,650 5,380 Repayment of long-term debt (6,928) (1,745) Dividends paid (1,051) (1,051) Purchase of treasury and common stock (1) (44) Net cash provided by financing activities 15,670 2,540 Net increase (decrease) in cash and cash equivalents 2,682 (8,967) Cash and cash equivalents at beginning of period 1,723 9,976 Cash and cash equivalents at end of period $ 4,405 $ 1,009 The accompanying notes are an integral part of these consolidated financial statements. ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) (In thousands) (Unaudited) Nine months ended September 30, 1996 1995 Reconciliation of net income to net cash provided by operating activities: Net income $ 5,921 $ 1,655 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 9,144 7,184 Impairment of proved properties - 1,673 Income in equity investees (47) - Gain on sale of oil and gas properties - (1,052) Dry hole costs 1,956 940 Abandonment and impairment of unproved properties 1,240 759 Deferred income taxes 2,271 42 Other 455 (56) 20,940 11,145 Changes in assets and liabilities: Accounts receivable (8,619) 466 Refundable income taxes 141 (437) Accounts payable and accrued expenses 4,720 581 Deferred income taxes (72) - Net cash provided by operating activities $17,110 $11,755 Supplemental schedule of noncash investing and financing activities: In March 1996, the Company acquired an additional 35% shareholder interest in St. Mary Operating Company for $234,000 and assumed net liabilities of $339,000. The accompanying notes are an integral part of these consolidated financial statements. ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) Note 1 - Basis of Presentation The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. They do not include all information and notes required by generally accepted accounting principles for complete financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the Notes to Consolidated Financial Statements of St. Mary Land & Exploration Company and Subsidiaries (the Company) for the year ended December 31, 1995 included elsewhere herein. In the opinion of Management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The accounting policies followed by the Company are set forth in Note 1 of the Notes to Consolidated Financial Statements of the Company for the year ended December 31, 1995. It is suggested that these financial statements be read in conjunction with the Consolidated Financial Statements and accompanying Notes to Consolidated Financial Statements. Note 2 - Investments In March 1996, the Company completed its purchase of the Anderman Group stock of St. Mary Operating Company ( SMOC ) at book value. 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 accounts for its investment in the Russian joint venture using the equity method of accounting. For the nine months ended September 30, 1996, the Company has recorded a gain of $405,000 as its equity in income from the Russian joint venture. The Company accounts for its investment in Summo Minerals Corporation ( Summo ) using the equity method of accounting. For the nine months ended September 30, 1996, the Company has recorded a loss of $358,000 as its equity in the losses of Summo. 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 following is pro forma revenue, income from continuing operations and per share data assuming this transaction was effective as of January 1 for the periods indicated. Pro Forma for the Nine Months Ended September 30, (in thousands, except per share amounts) (unaudited) 1996 1995 Total operating revenues $41,817 $30,036 Income from continuing operations $ 6,156 $ 2,005 Income per common share from continuing operations $ .70 $ .23 Note 3 - Contingencies On August 23, 1995, a class action law suit was filed against the Company in the 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. This suit was dismissed without prejudice on September 12, 1996 upon motion filed by counsel for the plaintiff class. Note 4 - Income Taxes Federal income tax expense for 1996 and 1995 differs from the amount that would be provided by applying the statutory U.S. Federal income tax rate to income before income taxes primarily due to Section 29 tax credits and percentage depletion. In 1995 the Company also utilized capital loss carryovers. Note 5 - Subsequent Events In November 1996, the Company adopted a stock option plan which covers a maximum of 700,000 shares. Options granted under the 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 will 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 options are transferrable to members of the optionee's family. The Company will adopt SFAS No. 123, "Accounting for Stock-Based Compensation," in its annual report on Form 10-K 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 262,372 options, exercisable at $20.50 per share, the fair market value on the date of issuance, in conjunction with the termination of future awards under the Company's SAR plan. The new stock option plan is subject to shareholder approval. In order to focus on development and exploration efforts in its five core operating areas, the Company decided in 1996 to monetize its interests in properties in Russia ("Russian Partnership Interest"). Upon the closing, which the Company expects to occur in the first quarter of 1997, the Company will receive cash consideration of approximately $5.2 million, approximately $1.7 million of common stock in Ural Petroleum Corporation and a receivable in the form of a retained production payment of approximately $10.3 million plus interest at 10% per 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, 1995 and 1994, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. As discussed in Notes 1, 3 and 4 to the consolidated financial statements, the Company changed its method of accounting for income taxes in 1993, its method of accounting for certain investments in debt and equity securities in 1994, and its method of accounting for impairment of long-lived assets in 1995. /S/ COOPERS & LYBRAND L.L.P. Denver, Colorado ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, except share amounts) December 31, 1995 1994 ASSETS Current assets: Cash and cash equivalents $ 1,723 $ 9,976 Accounts receivable 8,068 8,388 Prepaid expenses 850 165 Refundable income taxes 176 376 Total current assets 10,817 18,905 Property and equipment (successful efforts method), at cost: Proved oil and gas properties 165,750 150,350 Unproved oil and gas properties, net of impairment allowance of $2,245 in 1995 and $1,581 in 1994 11,752 8,358 Other 2,535 2,242 180,037 160,950 Less accumulated depletion, depreciation, amortization and impairment (108,392) (101,295) 71,645 59,655 Other assets: Investment in Russian joint venture 4,140 4,158 Investment in Summo Minerals Corporation 4,842 2,514 Other assets 4,682 4,160 13,664 10,832 $ 96,126 $ 89,392 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 7,715 $ 9,461 Long-term liabilities: Long-term debt 19,602 11,130 Deferred income taxes 1,228 1,758 Stock appreciation rights 1,178 958 Other noncurrent liabilities 121 51 22,129 13,897 Commitments and contingencies (Notes 1, 7, 8, 9, 10 and 11) Stockholders' equity: Common stock, $.01 par value; authorized - 15,000,000 shares; issued and outstanding - 8,761,855 shares in 1995 and 8,762,604 shares in 1994 88 88 Additional paid-in capital 15,835 15,845 Retained earnings 50,378 50,037 Unrealized gain on marketable equity securities - available for sale 15 64 Treasury stock - 2,572 shares, at cost (34) - Total stockholders' equity 66,282 66,034 $ 96,126 $ 89,392 The accompanying notes are an integral part of these consolidated ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In thousands, except share amounts) For the Years Ending December 31, 1995 1994 1993 Operating revenues: Oil and gas production $36,569 $38,239 $38,208 Gain on sale of proved properties 1,292 418 - Gas contract settlements and other revenues 789 6,128 424 Total operating revenues 38,650 44,785 38,632 Operating expenses: Oil and gas production 10,646 10,496 9,341 Depletion, depreciation and amortization 10,227 10,134 8,775 Impairment of proved properties 2,676 4,219 3,498 Exploration 5,073 8,104 5,457 Abandonment and impairment of unproved properties 2,359 1,023 1,020 General and administrative 5,328 5,261 4,712 Gas contract disputes and other 152 493 638 Loss in equity investees 579 348 659 Total operating expenses 37,040 40,078 34,100 Income from operations 1,610 4,707 4,532 Nonoperating income and (expense): Interest income 287 426 668 Interest expense (1,183) (951) (730) Income from continuing operations before income taxes 714 4,182 4,470 Income tax benefit (expense) 723 (445) (1,065) Income from continuing operations 1,437 3,737 3,405 Gain on sale of discontinued operations, net of income taxes 306 - - Income before cumulative effect of change in accounting principle 1,743 3,737 3,405 Cumulative effect of change in accounting principle - - 300 Net income $ 1,743 $ 3,737 $ 3,705 Net income per common share: Income from continuing operations $ .17 $ .43 $ .39 Gain on sale of discontinued operations .03 - - Cumulative effect of change in accounting principle - - .03 Net income per share $ .20 $ .43 $ .42 Weighted average common shares outstanding 8,760 8,763 8,763 The accompanying notes are an integral part of these consolidated financial statements. ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (In thousands, except share amounts) Unrealized Gain(Loss) Marketable Equity Additional Securities Common Stock Paid-In Retained Available Shares Amount Capital Earnings For Sale Balance, December 31, 1992 8,765,048 $88 $15,875 $45,399 $ - Net income - - - 3,705 - Cash dividends, $.16 per share - - - (1,402) - Purchase and retirement of common stock (2,444) - (30) - - Balance, December 31, 1993 8,762,604 88 15,845 47,702 - Adoption of SFAS No. 115 - - - - 589 Unrealized loss - - - - (525) Net income - - - 3,737 - Cash dividends, $.16 per share - - - (1,402) - 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 gain - - - - (49) Purchase and retirement of common stock and other (749) - (10) - - Balance, December 31, 1995 8,761,855 $ 88 $ 15,835 $50,378 $ 15 The accompanying notes are an integral part of these consolidated financial statements. ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) For the Years Ending December 31, 1995 1994 1993 Cash flows from operating activities: Cash received from oil and gas operations $33,663 $41,346 $35,800 Cash paid for oil and gas operations, including general and administrative expenses (13,051) (13,175) (11,246) Exploration expenses (3,672) (6,860) (4,406) Interest and other receipts 1,356 686 1,341 Interest paid (795) (767) (598) Income taxes refunded (paid) 212 (959) (1,216) Net cash provided by operating activities 17,713 20,271 19,675 Cash flows from investing activities: Proceeds from sale of oil and gas properties 2,337 221 642 Capital expenditures, including dry hole costs (22,657) (16,950) (13,492) Acquisition of oil and gas properties (8,111) (5,066) (4,848) Investment in Russian joint venture (297) (631) (2,546) Investment in Summo Minerals Corporation (4,528) (219) (305) Other 264 (499) 10 Net cash used by investing activities (32,992) (23,144) (20,539) Cash flows from financing activities: Proceeds from long-term debt 19,513 - 5,720 Repayment of long-term debt (11,041) (578) (2,462) Proceeds from issuance of common stock - - 3,222 Costs and fees related to public offering - - (151) Dividends paid (1,402) (1,402) (1,402) Other (44) - (30) Net cash provided (used) by financing activities 7,026 (1,980) 4,897 Net increase (decrease) in cash and cash equivalents (8,253) (4,853) 4,033 Cash and cash equivalents at beginning of period 9,976 14,829 10,796 Cash and cash equivalents at end of period $ 1,723 $ 9,976 $14,829 The accompanying notes are an integral part of these consolidated financial statements. ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) (In thousands) For the Years Ending December 31, 1995 1994 1993 Reconciliation of net income to net cash provided by operating activities: Net income $ 1,743 $ 3,737 $ 3,705 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization 10,227 10,134 8,775 Impairment of proved properties 2,676 4,219 3,498 Loss in equity investees 579 348 659 Gain on sale of oil and gas properties (1,535) (390) (43) Dry hole costs 1,529 2,407 1,201 Abandonment and impairment of unproved properties 2,359 1,023 1,020 Deferred income taxes (1,038) (835) 1 Cumulative effect of change in accounting principle - - (300) Other (407) 105 406 16,133 20,748 18,922 Changes in assets and liabilities: Accounts receivable 166 (450) 282 Refundable income taxes 200 448 1,095 Accounts payable and accrued expenses 706 (402) 605 Deferred income taxes 508 (73) (1,229) Net cash provided by operating activities $17,713 $20,271 $19,675 Supplemental schedule of noncash investing and financing activities: In July 1993, the Company sold one of its real estate assets for the assumption of the existing $492,000 mortgage. In January 1994, the Company acquired an additional 10.28% general partnership interest in Panterra Petroleum for approximately $1.3 million in cash and 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 buy out 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. The accompanying notes are an integral part of these consolidated financial statements. 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 a Delaware corporation engaged in oil and gas exploration, development and production in the United States and various foreign countries, including Russia, Canada and Trinidad and Tobago. Through September 1994, the majority of the Company s domestic operations and its international operations were managed by various individuals (the Anderman Group ) through Anderman/Smith Operating Company, now known as St. Mary Operating Company ( SMOC ). In October 1994, the Company assumed management of the domestic oil and gas administrative activities of SMOC and 79 employees of SMOC became employees of the Company. During 1995, the Company and the Anderman Group terminated their domestic joint participation and management program and agreed to the sale of all of the Anderman Group stock of SMOC to the Company at book value in 1996. In addition, the Company withdrew from all international partnerships managed by the Anderman Group with the exception of the partnerships with interests in Russia, Canada and Trinidad and Tobago. While these remaining international activities continue to be managed by the Anderman Group, the Company does not intend to participate in any new international ventures managed by the Anderman Group. Reclassifications: Certain amounts in the 1994 and 1993 consolidated financial statements have been reclassified to correspond to the 1995 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. 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 and do not present unanticipated credit concerns. 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. The Company has accounts with separate banks in Denver, Colorado, Dallas, Texas and Shreveport, Louisiana. At December 31, 1995 and 1994, the Company had $386,000 and $8,511,000 respectively, invested in money market funds consisting of U.S. Treasury obligations. 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. 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, which is determined using discounted future net revenues from the producing field. 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, $4,219,000 and $3,498,000 in 1995, 1994 and 1993, 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 a recovery of costs. 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. 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 (using the lower of (i) prices in effect at the time of production, (ii) current market price or (iii) contract price, and taking into consideration the financial stability of the other owners) 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 $868,000 and $896,000 at December 31, 1995 and 1994, 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 $10,000 and $16,000 on these contracts for the years ended December 31, 1995 and 1994, respectively. The Company also uses interest rate cap and swap agreements as a hedge against future interest rate increases on its long-term debt. Gains or losses on these arrangements are treated as adjustments to interest expense. Premiums paid on these agreements are amortized into expense over the lives of the agreements. 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. 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 dilutive for any periods presented. 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 (in thousands): December 31, 1995 1994 Accrued oil and gas sales: Due from third parties $4,827 $4,066 Due from St. Mary Operating Company 1,958 2,277 Due from joint interest owners 1,283 2,045 $8,068 $8,388 3. Marketable Equity Securities: As of December 31, 1995 and 1994, the Company owned 9,028,003 (51% of total shares outstanding) and 5,598,003 (42% of total shares outstanding) shares of Summo Minerals Corporation ( Summo ), an international mining company, with a total cost of $5,108,000 and $2,524,000, and warrants to acquire an additional 5,495,000 and 2,295,000 shares, respectively. Exercise prices for the warrants range from $.77 to $1.01, using the exchange rate in effect on December 31, 1995 ($.73). Summo completed its initial public offering effective October 31, 1994 at $.44 per share. The market value of this investment was $7,945,000 at December 31, 1995 and $5,945,000 at December 31, 1994. The Company s investment in Summo is accounted for using the equity method of accounting because the Company s ownership is expected to drop below 50% due to a secondary offering during 1996. For the years ending December 31, 1995 and 1994, the Company reported equity in losses from Summo of $257,000 and $20,000, respectively. As of December 31, 1995 and 1994, the Company owned 67,017 and 88,017 shares of Arauco Resources Corporation ( Arauco ), an international mining company with a total cost of $28,000 and $37,000, and a market value net of tax of $18,000 and $53,000, respectively. Effective October 4, 1994, the Company exchanged 1,034,179 shares of Arauco for 324,042 shares and warrants to purchase an additional 324,040 shares of Santa Elina Gold Corporation ( Santa Elina ), an international mining company. No gain or loss was recognized on the exchange. In January 1995, Santa Elina completed its initial public offering at $1.50 per share. As of December 31, 1995 and 1994, the Company owned 296,042 and 324,042 shares of Santa Elina with a total cost of $400,000 and $437,000, and a market value net of tax of $425,000 and $485,000, respectively. The Company adopted SFAS No. 115 in 1994 and classifies the investments in Arauco and Santa Elina as marketable equity securities available for sale. Accordingly, unrealized gains and losses for these investments are recorded in stockholders equity. The combined net unrealized gain for these investments was $15,000 at December 31, 1995 and $64,000 at December 31, 1994. During 1995, the Company realized proceeds from the sale of Arauco and Santa Elina shares of $25,000 and $44,000, respectively. The Company used the average cost method and realized a gain of $16,000 on the sale of 21,000 shares of Arauco and $6,000 on the sale of 28,000 shares of Santa Elina. 4. Income Taxes: The provision for income taxes consists of the following: For the Years Ended December 31, 1995 1994 1993 (In thousands) Current taxes: Federal $ 77 $ 835 $ 477 State 396 445 587 Deferred taxes (1,038) (835) 1 Total income tax expense (benefit) $ (565) $ 445 $1,065 Continuing operations $ (723) $ 445 $1,065 Discontinued operations 158 - - Total income tax expense (benefit) $ (565) $ 445 $1,065 The above taxes are net of alternative fuel credits (Section 29) of $624,000 in 1995, $1,333,000 in 1994 and $735,000 in 1993. Effective January 1, 1993, the Company adopted the liability method of accounting for income taxes under SFAS No. 109, Accounting for Income Taxes. Prior to 1993, income taxes were calculated in accordance with Accounting Principles Board Opinion No. 11. The adoption of SFAS No. 109 resulted in a one time benefit of $300,000 which is reflected as a cumulative effect of a change in accounting principle. Other than the cumulative effect adjustment, the adoption of SFAS No. 109 did not have a material effect on 1993 results of operations. The components of the net deferred tax liability as of December 31, 1995 and 1994 under SFAS No. 109 were as follows (in thousands): December 31 1995 1994 Deferred tax assets Non-current Other assets $(1,458) $(1,756) State tax net operating loss carryforward (1,402) (1,594) Alternative minimum tax credit carryforward (565) (545) Federal capital loss carryforward - (292) Total deferred tax assets (3,425) (4,187) Valuation allowance 1,402 1,814 Net deferred tax assets (2,023) (2,373) Deferred tax liabilities Non-current Oil and gas properties 2,886 3,824 Net other assets 365 307 Net deferred tax liability $1,228 $1,758 At December 31, 1995, the Company had state net operating loss carryforwards of approximately $23.5 million which expire between 1996 and 2007 and alternative minimum tax credit carryforwards of $565,000 which may be carried forward indefinitely. The Company's 1995 valuation allowance relates to its state net operating loss carryforwards since the Company has historically recognized net operating losses in the states with carryforwards and anticipates carryforwards from prior years will expire before they can be utilized. The net change in valuation allowance in 1995 is primarily a result of the recognition of a capital loss carryover. 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 and the cumulative effect of change in accounting principle for the following reasons: For the Years Ended December 31, 1995 1994 1993 (In thousands) Federal statutory taxes $ 242 $1,422 $1,520 Increase (reduction) in taxes resulting from: State taxes (net of Federal benefit) 261 294 387 Statutory depletion (173) (174) (187) Alternative fuel credits (Section 29) (624) (1,333) (735) Change in valuation allowance (412) 225 - Other (17) 11 80 Income tax expense (benefit) $ (723) $ 445 $1,065 5. Long-term Debt and Notes Payable: In April 1995, the Company amended its long-term revolving credit facility dated March 1, 1993 and extended its maturity to February 28, 1998. Borrowings under this new agreement are limited to the lesser of $30,000,000 or the current borrowing base, as determined by the bank semi-annually. The borrowing base at December 31, 1995 and 1994 was $30,000,000 and $25,000,000, respectively. 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 will be collateralized by approximately 75% of the value of the Company's producing oil and gas properties. In addition, the Company must comply with certain other covenants, including maintenance of stockholders' equity of not less than $27 million, limitations on additional indebtedness and payment of dividends. In 1995, at the Company's request the loan commitment was reduced to $10,000,000. However, the Company has the option of increasing the commitment to the maximum allowed. As of December 31, 1995, $8,300,000 was outstanding under this credit facility. Through March 31, 1995, interest on borrowings was computed at the bank s prime rate or LIBOR plus 1.5% (8.5% or 8.0% and 6.0% or 4.9% respectively, at December 31, 1994 and 1993). 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%, Prime rate or Prime rate or less than 40% LIBOR + .75% LIBOR + 1.0% Greater than 40%, Prime rate or Prime rate or less than 50% LIBOR + 1.0% LIBOR + 1.25% Greater than 50%, Prime rate + Prime rate + .125% or .125% or LIBOR + 1.25% LIBOR + 1.5% Commitment Fees on Unused Portion Short Term Tranche Long Term Tranche Less than 50% of available borrowings .125% .25% Greater than 50% of available borrowings .375% .50% At December 31, 1995, the Company's debt to capitalization ratio as defined was 24% and interest on borrowings is computed at the bank s prime rate or LIBOR plus .5% (8.5% or 6.16% at December 31, 1995). In November 1991, the Company entered into a three year interest rate cap agreement which limited the maximum LIBOR interest rate on a principal amount of $3,000,000 to 9%. The interest rate cap agreement expired in 1994. In connection with the acquisition of its 50% general partnership interest in Panterra, the Company assumed 50% of a bank note payable which was restated in April 1993. The note, which was due April 30, 1998, was payable in monthly installments of $350,000, excluding interest. Prior to its restatement, the agreement provided for borrowings at the bank's prime rate plus 2% or LIBOR plus 3%. The restated agreement provided for borrowings at the lower of the bank's prime rate plus 1% or LIBOR plus 2.25% (9.5% or 8.75% and 7.0% or 5.63% respectively, at December 31, 1994 and 1993). The note was collateralized by substantially all of Panterra's oil and gas properties and cash accounts. On February 6, 1995, Panterra entered into a credit agreement with a bank whereby funds were advanced to pay in full the restated note due April 30, 1998. The new credit agreement includes a two year revolving period converting to a five year amortizing loan on February 6, 1997. During the revolving period, interest is payable at the bank's prime rate or LIBOR plus 1.5% (8.5% or 7.16%, at December 31, 1995). 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 commitment amount which will not exceed $20,000,000. During the amortization period, monthly principal payments are payable at rates decreasing from 2.0% to 1.4% of the outstanding balance through February 2002, at which time the remaining principal balance is due. The new Panterra credit agreement is collateralized by all of Panterra's oil and gas properties and contains restrictive covenants relating to acquisition of assets, new debt agreements and the maintenance of certain minimum financial statement ratios by Panterra. The Company s proportionate share of the liability under Panterra's bank note payable is 74%. Panterra had entered into an interest rate swap agreement which expired in July 1994. Under this agreement Panterra paid interest on the $5,000,000 of notional principal at a fixed rate of 7.98% and received interest on the notional principal at a floating rate equal to LIBOR. Panterra also entered into an interest rate cap agreement which limited the interest rate to 9% on a principal amount of $5,000,000 from July 1992 through July 1993. There were no outstanding swap agreements at December 31, 1994 or 1995. 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) 1996 $ - 1997 2,252 1998 2,991 1999 2,954 2000 2,662 Thereafter 8,743 $19,602 6. Gas Contract Settlements: During 1994 and 1993, the Company settled several gas contract disputes with pipeline companies, recognizing income of $5,741,000 and $235,000 respectively. The Company settled the final two gas contract disputes during 1994. 7. Commitments and Contingencies: The Company leases office space under operating leases which expire in 1997. The annual minimum lease payments approximate $398,000. The Company has noncancelable annual leases with affiliates of approximately $239,000. Rent expense, net of sublease income, was $131,000, $166,000 and $195,000 in 1995, 1994 and 1993, respectively. Pursuant to a purchase and sale agreement between Panterra and Chevron U.S.A., Inc. ("Chevron"), Panterra was obligated to pay Chevron an annual production payment each March 1 through December 31, 1995 if crude oil prices reached certain specified minimum levels, which escalated from $22.00 to $26.64 from 1991 to 1995. No payments were made under this agreement in 1993, 1994 or 1995. The Company has the following commodity contracts to hedge or otherwise reduce the impact of oil and gas price fluctuations in place as of December 31, 1995: Product Volumes/Month Fixed Price Duration Natural Gas 22,500 MMBtu $1.90 1/96 - 6/98 Natural Gas 15,000 MMBtu $1.94 3/96 - 2/98 Natural Gas 24,000 MMBtu $1.83 1/96 - 12/97 Natural Gas 15,000 MMBtu $2.065 1/96 - 5/97 Natural Gas 133,500 MMBtu $1.73 1/96 - 3/96 Natural Gas 96,000 MMBtu $1.96 1/96 - 3/96 Natural Gas 23,000 MMBtu $1.63 1/96 - 2/96 Oil 1,125 Bbls $16.98 1/96 - 9/97 Oil 1,000 Bbls $16.95 1/96 - 4/97 Oil 3,200 Bbls $17.95 1/96 - 1/97 Oil 1,200 Bbls $18.44 2/96 - 1/97 Oil 22,100 Bbls $18.36 - 18.40 1/96 - 12/96 Oil 1,667 Bbls $18.61 1/96 - 6/96 Oil 2,500 Bbls $17.80 1/96 Oil 37,500 Bbls $18.50 - 19.10 1/96 - 3/96 The fair value of the Company's commodity hedging contracts based on year end futures pricing would require the Company to pay approximately $415,000, if these contracts were terminated on December 31, 1995. During 1993, St. Mary Operating Company, which operates a number of wells in which the Company has a working interest, was named with others as a defendant in four Mississippi state court lawsuits in which property owners were seeking damages for alleged contamination of four well sites. The plaintiffs sought $10 million in compensatory damages and $20 million in punitive damages, an amount which exceeded the net worth of SMOC. During 1994, one suit was settled for an amount which was not material, a large portion of which was covered by insurance, and SMOC was dismissed as a defendant in a second suit. In early 1996, one of the remaining suits was settled for an amount which is not material, and minor details regarding the settlement of the other remaining suit are currently being negotiated. Whether insurance will cover the latter settlements is uncertain at present. During 1995, the Company and other unrelated parties were named as defendants in a class action suit filed in Oklahoma seeking payment of royalties on amounts received in prior gas contract settlements. While the Company'sleases state that royalties are paid only on oil and gas produced and sold, the end result of any litigation seeking royalty payments on amounts received in oil and gas settlements cannot be known in advance, and it is possible that a judgment adverse to the Company could result even though gas was not produced and sold. Management believes its position is legally correct and plans a vigorous defense of this suit. In the event of adverse judgment, however, management believes the maximum exposure of the Company in this litigation, exclusive of interest, if any, would be approximately $4.5 million. The Company has no material exposure to claims for such payments outside of Oklahoma. The Company is also aware that, in two appellate proceedings in which the Company is not involved, the Oklahoma Supreme Court has been asked to address issues regarding the entitlement of lessors to royalty payments on amounts received by oil and gas working interest owners as a result of gas contract claims. While the Company believes that royalties are not owed until oil and gas is produced and sold, the decision of the Oklahoma Supreme Court cannot be known in advance and it is possible that the ruling will establish a right of royalty owners to payment. Such a ruling could adversely affect the Company's position in the royalty litigation described above. 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 will record compensation expense once it recovers its investment and net profits attributable to the properties are payable to the employees. 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 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 $220,247, $268,286 and $222,191 in 1995, 1994 and 1993, respectively. 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. The exact sale price depends upon the period of time the stock has been held by the participant. At December 31, 1995, there were 33,559 shares issued and outstanding under the Plan. The Company's stock price was $14.00 at December 31, 1995. In 1990 and 1991, the Company granted certain officers options to acquire 54,612 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. 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 $183,000, $93,000 and $64,000 for the years ended December 31, 1995, 1994 and 1993, respectively. In October 1995, the FASB issued SFAS No. 123, Accounting for Stock-Based Compensation. This standard establishes a fair value method of accounting for stock-based compensation plans either through recognition or disclosure. The Company will adopt this standard in 1996 through compliance with the disclosure requirements set forth in SFAS No. 123. It is not believed the adoption of this standard will have a material impact on the financial position or results of operations of the Company. 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, 1995, 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, 1995 1994 1993 (In thousands) Service cost - benefits earned during the year $ 79 $129 $105 Interest cost on projected benefit obligations 51 45 28 Actual (return) loss on plan assets (133) 27 (63) Net amortization (deferral) 61 (94) 36 Net pension expense $ 58 $107 $106 A reconciliation of the funded status of the plans to accrued pension liability is as follows: Primary Plan Supplemental Plan December 31, December 31, 1995 1994 1995 1994 (In thousands) Actuarial present value of benefits based on service to date and present pay levels: Vested $263 $396 $140 $ - Nonvested 63 67 - 1 Accumulated benefit obligation 326 463 140 1 Additional amounts related to pay increases 219 261 127 10 Projected benefit obligation 545 724 267 11 Plan assets at fair value 810 712 - - Projected benefit obligation (in excess of) or less than plan assets 265 (12) (267) (11) Unrecognized (gain) loss (261) 15 192 6 Unrecognized net asset (17) (28) - - Accrued pension liability included in the consolidated balance sheets $(13) $ (25) $(75) $(5) Actuarial assumptions for December 31, 1995 and 1994 are as follows: 1995 1996 Discount Rate 7.50% 8.50% Average salary growth rate 5.00% 6.00% Return on plan assets 8.00% 8.00% 10. Related Party Transactions: A majority of the Company'soil and gas operations, other than Louisiana royalties, including acquisition of unproved properties, are administered by SMOC. Operations were conducted under a domestic agreement with SMOC and 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 itwould 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. The Company s agreement with the Anderman Group involves its payment of 75% of acquisition costs and of costs directly associated with the acquisition, including geological costs which may be required by the foreign license agreement. The Company's resulting ownership interest in the foreign projects prior to the involvement of unrelated third parties is 45% and the interest of the Anderman Group is 55%. Administrative and operational services were provided for these projects by SMOC of which the Company pays 65%. In certain circumstances, the Company agreed to fund, through non-recourse loans to individuals in the Anderman Group, up to 5% of the total project development costs of the Company and the Anderman Group. At December 31, 1995 and 1994, the amounts of these loans was approximately $622,000 and $555,000, respectively. In addition, certain employees of SMOC and outside consultants received net profits interests of up to 1.5% of the Company's interests in certain international projects. During 1995, the Company recorded a charge to operations of $252,000 resulting from its withdrawal from the international partnerships. Billings from SMOC, which represent charges for lease operating, exploration, development and general and administrative expenses, amounted to $11,451,000, $14,008,000 and $10,071,000 for the years ended December 31, 1995, 1994 and 1993, respectively. As of December 31, 1995 and 1994, accounts payable included $746,000 and $525,000, respectively, owed to SMOC. SMOC is also responsible for collecting revenues from purchasers for a number of the Company'swells. During 1995, 1994 and 1993 approximately 33%, 32% and 29%, respectively, of the Company'soil and gas sales were collected by 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. Financing commitments have been obtained for the joint venture which are non-recourse to the Company. The joint venture has received $32.5 million from loan advances through December 31, 1995. The joint venture received additional funding of $10 million in February 1996, and anticipates the committed balance of $10 million to be funded later in 1996. The Company expects all of the capital requirements for 1996 to be funded from cash flow and non-recourse bank financing. Through December 31, 1995 the Company had expended $7.5 million on the Russian project of which $4.1 million has been capitalized. The Company's impairment policy with respect to this investment is consistent with its policy for proved oil and gas properties using future net revenues after debt service. At December 31, 1995, the undiscounted future net revenues attributable to the Company's share of the Russian joint venture's proved reserves was $36.6 million (after debt repayment). The present value of estimated future net cash flows before income taxes discounted at 10% was $20.4 million in accordance with Securities and Exchange Commission guidelines and may not be indicative of market value. Summarized combined financial information of the Russian joint venture is shown below: For the Years Ended December 31, 1995 1994 1993 (Unaudited, in thousands) Income Statement: Oil and gas revenues $29,479 $15,035 $ 1,643 Operating expenses 22,547 12,707 6,236 Interest and other expenses 8,966 5,831 1,642 Net income (loss) $(2,034) $(3,503) $(6,235) Balance Sheet: Current assets $10,105 $12,974 $ 3,982 Non-current assets 49,300 35,034 26,851 Current liabilities 10,569 11,700 4,904 Non-current liabilities 50,614 48,007 32,170 Shareholders' deficit (1,778) (11,699) (6,241) 12. Disposal of Real Estate Segment: Effective June 30, 1992, the Company made the decision to sell its remaining real estate projects. Accordingly, the Company's real estate activities have been presented as discontinued operations in the statements of income. For 1992, the discontinued real estate segment had revenues of $1,298,000, costs and expenses of $647,000 and a provision for income taxes of $221,000 resulting in income from discontinued operations of $430,000. The Company recorded a gain on the sale of discontinued operations of $306,000, net of income taxes of $158,000 in 1995. The Company had no income or loss from discontinued operations in 1994 and 1993. The Company's remaining real estate assets consist of land held for sale with a carrying cost of $1,311,000 and $1,806,000 as of December 31, 1995 and 1994, respectively, which is less than the estimated net realizable values. 13. Disclosures About Oil and Gas Producing Activities: Major Customers: There were no sales to individual customers constituting 10% or more of total revenues during 1995, 1994 and 1993. 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, 1995 1994 1993 (In thousands) Unproved property acquisitions $2,937 $ 3,228 $ 1,847 Proved property acquisitions 8,111 12,279 4,848 Exploration costs: Domestic 8,746 9,481 9,013 International (112) 877 647 Development costs 12,625 5,946 7,079 Total $32,307 $31,811 $23,434 Russian joint venture, equity method $ 3,213 $ 1,551 $ 1,872 Oil and Gas Reserve Quantities (Unaudited): The reserve information as of December 31, 1995, 1994, 1993 and 1992 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. 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, 1995 1994 1993 Oil Oil Oil or or or Condensate Gas Condensate Gas Condensate Gas (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) Total proved U.S. reserves: Developed and undeveloped: Beginning of year 6,677 62,515 4,590 56,535 4,594 51,663 Revisions of previous estimates 39 515 446 5,064 (428) 5,927 Discoveries and extensions 894 16,069 658 10,274 566 9,262 Purchase of minerals in place 1,095 9,274 2,062 3,262 756 1,200 Sale of reserves (152) (234) (142) (43) (52) (370) Produc- tion (1,044) (12,434) (937) (12,577) (846) (11,147) End of year(a) 7,509 75,705 6,677 62,515 4,590 56,535 Proved developed U.S. reserves: Beginning of year 6,050 58,661 4,160 54,420 4,296 48,466 End of year 6,829 66,230 6,050 58,661 4,160 54,420 Russian joint venture reserves, end of year 7,247 2,536 9,915 - 10,921 - (a) At December 31, 1995, 1994 and 1993, includes approximately 1,895, 2,500 and 2,800 MMcf, respectively representing the Company's underproduced gas balancing position. 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. 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, 1995 1994 1993 (In thousands) Future cash inflows $292,149 $202,454 $190,257 Future production and development costs (105,520) (73,204) (54,956) Future income taxes (49,383) (28,977) (38,499) Future net cash flows 137,246 100,273 96,802 10% annual discount (49,547) (39,407) (32,311) Standardized measure of discounted future net cash flows $ 87,699 $ 60,866 $ 64,491 Russian joint venture standardized measure of discounted future net cash flows $ 15,077 $ 25,242 $ 5,431 The principal sources of change in the standardized measure of discounted future net cash flows are as follows: For the Years Ended December 31, 1995 1994 1993 (In thousands) Standardized measure, beginning of year $60,866 $64,491 $62,202 Sales of oil and gas produced, net of production costs (25,923) (27,743) (28,867) Net changes in prices and production costs 23,432 (16,196) (1,993) Extensions, discoveries and other, net of production costs 23,863 12,507 15,066 Purchase of minerals in place 10,287 11,114 6,133 Development costs incurred during the year 2,189 1,655 1,041 Changes in estimated future development costs (1,801) (1,227) (493) Revisions of previous quantity estimates 856 6,941 3,901 Accretion of discount 8,469 9,052 8,962 Sales of reserves in place (1,365) - - Net change in income taxes (12,817) 6,771 1,237 Other (357) (6,499) (2,698) Standardized measure, end of year $87,699 $60,866 $64,491 EXHIBIT A January 13, 1997 St. Mary Land & Exploration Company 1776 Lincoln Street, Suite 1100 Denver, Colorado 80203 Attention: Douglas W. York At your request we have prepared an estimate of the reserves and future production and income attributable to certain leasehold and royalty interests of St. Mary Land & Exploration Company as of December 31, 1996. Ryder Scott Company Petroleum Engineers (Ryder Scott) has evaluated approximately 496 properties which account for approximately 81.5 percent of the future net income discounted at ten percent as of December 31, 1996. We have been assured that the income data have been estimated using the Securities and Exchange Commission (SEC) guidelines for future cost and price parameters. The results of this study are summarized below: The estimated reserve quantities and future income quantities presented in this report are related to hydrocarbon prices. December 31, 1996 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly due to seasonal price variations. Therefore, quantities of reserves actually recovered and quantities of income actually received may differ significantly from the estimated quantities presented in this report. SEC PARAMETERS Estimated Net Reserve and Income Data Certain Leasehold and Royalty Interests of St. Mary Land & Exploration Company As Of December 31, 1996 Total Proved Net Oil Net Gas Future Net Income M Barrels MMCF Discounted at 10% Evaluated by Ryder Scott at 12-31-96 8,085.3 93,441 $ 241,646,047 Evaluated by St. Mary 2,605.4 33,616 $ 54,815,193 Total Proved Reserves 10,690.7 127,057 $ 296,461,240 Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes have been represented to Ryder Scott Company as sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas where the gas reserves are located. The deductions are comprised of the production taxes, normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs and St. Mary Land & Exploration Company's estimate of revenue from their current gas balancing position. The future net income is before the deduction of state and federal income taxes and general corporate overhead, and has not been adjusted for outstanding loans which may exist nor does it include any adjustments for cash on hand or undistributed income. The discounted future net income shown above is based on a discount rate of 10 percent per annum compounded annually. Reserves Included in This Report The proved reserves, as evaluated by Ryder Scott Company, included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4- 10(a) as clarified by subsequent Commission Staff Accounting Bulletins. Our definitions of proved reserves are attached. Reserve Estimates In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such other methods were more appropriate in our opinion. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive in our opinion. Reserves were estimated by the volumetric method in those cases where there was inadequate historical performance data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. Future Production Rates Initial production rates are based on the current producing rates for those reservoirs now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant,, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. The future anticipated decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were projected to commence at an anticipated date of delivery which was furnished by St. Mary Land & Exploration Company. In general, we estimate that gas production rates will continue to be the same as the average rate for the latest available 12 month of actual production until such time that the well or wells are incapable of producing at this rate. Our general policy on estimates of future gas production rates is adjusted when necessary to reflect actual gas market conditions in specific cases. The future production rates from reservoirs now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. Hydrocarbon Prices St. Mary Land & Exploration Company furnished us with hydrocarbon prices in effect at December 31, 1996, a West Texas Intermediate crude oil price of $25.08 per barrel and Gulf Coast spot gas price of $3.736 per MMBTU. Product prices which are actually used for each property reflect adjustment from the above stated prices for gravity, quality, local conditions and/or distance from market. These prices were held constant to depletion of the properties. In accordance with Securities and Exchange Commission guidelines, changes in hydrocarbon prices subsequent to December 31, 1996 were not considered in this report. Costs Operating costs for the leases and wells in this report were furnished by St. Mary Land & Exploration Company. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under the terms of operating agreements. Development costs were furnished to us by St. Mary Land & Exploration Company and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. Ryder Scott has accepted the operating and development cost data supplied by St. Mary Land & Exploration Company's request, this study does not consider the salvage value of the lease equipment or the abandonment cost since both have been assumed to be relatively insignificant and tend to offset each other. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses and exploration and development prepayments which are not charged directly to the leases or wells. General Ryder Scott Company performed the reserve analyses and projections of future production for these interests. However, at the request of St. Mary Land & Exploration Company, the economic analyses were performed by St. Mary Land & Exploration Company on Munro Garrett International's economic program "Advanced Reserves and Information Evaluation System (ARIES)." Ryder Scott has confirmed that the values used for scheduling the individual wells' production were correct. We performed such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein. It is our opinion that the data presented for the properties we have evaluated fairly reflect the estimated net reserves and future income based on the prices and costs provided by St. Mary Land & Exploration Company. While it may reasonably be anticipated that the prices received by St. Mary Land & Exploration Company for the sale of its production may be higher or lower than the prices used in this evaluation as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. The reserve estimates presented herein are based upon a detailed study of the properties in which St. Mary Land & Exploration Company owns an interest; however, we have not made any field examination of the properties. St. Mary Land & Exploration Company has provided Ryder Scott with an ARIES database with production data and well test data where available. Ryder Scott has accepted this data as accurate and not verified or updated the data provided and have based our reserve estimates on this data as provided. It should be noted that additional historical data, both production and well test data, is available on certain properties through public sources of information. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. St. Mary Land & Exploration Company has informed us that they have furnished us all of the production information, accounts, records, geological and engineering data and reports and other data required for this investigation. The ownership interests, prices, product classifications relating to prices, gas balancing information and other factual data furnished to Ryder Scott by St. Mary Land & Exploration Company in connection with this investigation were accepted without independent verification. The estimates presented in this report are based on data available through December 31, 1996. Neither Ryder Scott Company nor any of its employees has any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties. This report was prepared for the exclusive use of St. Mary Land & Exploration Company. The data, work papers and maps used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY PETROLEUM ENGINEERS Gary Krieger, P.E. Vice President GK:ph (SEAL) COLORADO REGISTERED PROFESSIONAL ENGINEER Gary Grant Krieger, No. 28782 No dealer, salesperson or any other person has been authorized to give any information or to make any representations in connection with this offering other than those contained in this Prospectus. Any information or representation not herein contained, if given or made, must not be relied upon as having been authorized by the Company. This Prospectus does not constitute an offer to sell or a solicitation of an offer to buy any security other than the securities offered by this Prospectus, nor does it constitute an offer to sell or a solicitation of an offer to buy the securities by any person in any jurisdiction where such offer or solicitation is not authorized, or in which the person making such offer is not qualified to do so, or to any person to whom it is unlawful to make such offer or solicitation. The delivery of this Prospectus shall not, under any circumstances, create any implication that there has been no change in the affairs of the Company since the date hereof. TABLE OF CONTENTS Page Prospectus Summary ................ Risk Factors....................... Use of Proceeds.................... Capitalization..................... Price Range of Common Stock........ Dividend Policy.................... Selected Consolidated Financial Data..................... Management's Discussion and Analysis of Financial Condition and Results of Operations....................... Business and Properties............ Management......................... Description of Common Stock........ Underwriting....................... Legal Matters...................... Experts............................ Available Information.............. Incorporation of Certain Documents by Reference............ Glossary........................... Index to Consolidated Financial Statements.............. Summary Reserve Report of Ryder Scott Company.................... Exhibit A 2,000,000 Shares [ST. MARY LOGO] Common Stock _____________________ PROSPECTUS _____________________ Morgan Keegan & Company, Inc. A.G. Edwards & Sons, Inc. Hanifen, Imhoff Inc. PART II INFORMATION NOT REQUIRED IN PROSPECTUS Item 14. Other Expenses of Issuance and Distribution. The estimated expenses of the offering, all of which are to be borne by the Company, are as follows: Registration Fee Under Securities Act of 1933 and NASD Registration Fee........................... $26,978 Printing and Engraving............................. 50,000* Accounting Fees and Expenses....................... 45,000* Legal Fees and Expenses............................ 40,000* Blue Sky Fees and Expenses (including related legal fees).................. 10,000* Transfer Agent Fees................................ 1,000* Miscellaneous...................................... 27,022* Total......................................... $200,000* ________________ *Estimated Item 15. Indemnification of Directors and Officers. As permitted by the provisions of the Delaware General Corporation Law, the Certificate of Incorporation eliminates in certain circumstances the monetary liability of directors of the Company for a breach of their fiduciary duty as directors. These provisions do not eliminate the liability of a director (i) for a breach of the director's duty of loyalty to the Company or its stockholders; (ii) for acts or omissions by a director not in good faith or which involve intentional misconduct or a knowing violation of law; (iii) for liability arising under Section 174 of the Delaware General Corporation Law (relating to the declaration of dividends and purchase or redemption of shares in violation of the Delaware General Corporation Law); or (iv) for any transaction from which the director derived an improper personal benefit. In addition, these provisions to not eliminate the liability of a director for violations of federal securities laws, nor do they limit the rights of the Company or its stockholders, in appropriate circumstances, to seek equitable remedies such as injunctive or other forms of non-monetary relief. Such remedies may not be effective in all cases. The Company's Certificate of Incorporation and Bylaws provide that the Company shall indemnify all directors and officers of the Company to the full extent permitted by the Delaware General Corporation Law. Under such provisions, any director or officer, who in his capacity as such is made or threatened to be made, a party to any suit or proceeding, may be indemnified if the Board determines such director or officer acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interest of the Company. The Certificate, Bylaws and the Delaware General Corporation Law further provide that such indemnification is not exclusive of any other rights to which such individuals may be entitled under the Certificate, the Bylaws, any agreement, vote of stockholders or disinterested directors or otherwise. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers or persons controlling the Company pursuant to the foregoing provisions, the Company has been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is therefore unenforceable. Item 16. Exhibits. The following Exhibits are filed with or incorporated into this Form S-3 Registration Statement pursuant to Item 601 of Regulation S-K: 1.1 Form of Underwriting Agreement 5.1 Opinion of Cohen Brame & Smith Professional Corporation 13.1 The Company's Annual Report on Form 10-K for the year ended December 31, 1995** 13.2 The Company's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 1996, June 30, 1996 and September 30, 1996, as amended by a Form 10-Q/A dated November 15, 1996** 13.3 The Company's Current Report on Form 8-K dated June 28, 1996, as amended by a Form 8-K/A dated June 28, 1996, regarding the acquisition of an interest in certain of the assets of Siete Oil and Gas Company** 13.4 The Company's Current Report on Form 8-K dated December 16, 1996 regarding the sale of the Company's Russian Partnership Interest** 13.5 The Company's Current Report on Form 8-K dated January 28, 1997 regarding certain exhibits** 13.6 The Company's Registration Statement on Form 8-A filed November 18, 1992** 23.1 Consent of Cohen Brame & Smith Professional Corporation (included in Exhibit 5.1 above) 23.2 Consent of Coopers & Lybrand L.L.P. 23.3 Consent of Ryder Scott Company 24.1 Power of Attorney (included on signature page) _________________ * To be filed by amendment. ** Incorporated by reference to the Company's Report or Registration Statement filed on the Form and on the date or for the period or periods indicated (Exchange Act File No. 0-20872). Item 17. Undertakings. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Company pursuant to the foregoing provisions, or otherwise, the Company has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Company of expenses incurred or paid by a director, officer or controlling person of the Company in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Company will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. The undersigned Company hereby undertakes that: (1) For the purposes of determining any liability under the Securities Act of 1933, each filing of the Company's annual report pursuant to section 13(a) or section 15(d) of the Securities Exchanges Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (2) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (3) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the Company certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-3, and has duly caused this Form S-3 Registration Statement to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Denver, State of Colorado, on the 28th day of January, 1997. ST. MARY LAND & EXPLORATION COMPANY 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 agent with full power of substitution and resubstitution, for him and in his name, place and stead, and any and all capacities, to sign any amendments, including post effective amendments and any amendment pursuant to Rule 462 of the Securities Act of 1933, to this Registration Statement on Form S-3, 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 Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated. Signatures Title Date /s/ Thomas E. Congdon Chairman of the Thomas E. Congdon Board of Directors January 28, 1997 /s/ Mark A. Hellerstein President, Chief January 28, 1997 Mark A. Hellerstein Executive Officer (Principal Executive Officer) /s/ Ronald D. Boone Executive Vice January 28, 1997 Ronald D. Boone President, Chief Operating Officer and Director (Principal Executive Officer) /s/ David L. Henry Vice President-Finance January 28, 1997 David L. Henry and Chief Financial Officer (Principal Financial and Accounting Officer) /s/ Richard C. Norris Vice President - January 28, 1997 Richard C. Norris Accounting and Administration and Treasurer /s/ Larry W. Bickle Director January 28, 1997 Larry W. Bickle /s/ David C. Dudley Director January 28, 1997 David C. Dudley /s/ Richard C. Kraus Director January 28, 1997 Richard C. Kraus /s/ R. James Nicholson Director January 28, 1997 R. James Nicholson /s/ Arend J. Sandbulte Director January 28, 1997 Arend J. Sandbulte /s/ John M. Seidl Director January 28, 1997 John M. Seidl