SM Energy Company
Annual Report 2003

Plain-text annual report

R E P E A T A B I L I T Y Annual Report 2003 St. Mary Land & Exploration Company has been one of the top performing E & P companies since going public in 1992. The extraordinary returns we have provided our stockholders since our Company’s inception in 1908 have been based on a foundation of core values. For 95 years, St. Mary has embodied a culture of integrity, passion, knowledge, fairness, trust, and social responsibility. Our consistent growth and returns over a long period of time are due to our proven ability to repeat success. Operating in five core areas with superior technical teams provides the opportunities necessary to create and develop projects that will grow St. Mary to the next level. Over the years, each core area has developed a major project that has provided growth and the repeatability that increases stockholder value year after year. COMPANY AT A GLANCE Our Mission St. Mary Land & Exploration Company was founded in 1908 and incorporated in 1915. We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil in five core areas in the United States. Our mission is to build value by adding value at every phase of the business, from prospect generation to reservoir engineering to drilling to production to marketing to finance and to administration. Our goal is to provide a long-term return to our stockholders in the top-quartile of our peers while preserving underlying capital. We plan to achieve this by attracting, motivating, and retaining a talented staff; the intelligent use of new technologies; and a focus on growing net asset value per share. While growing our company, we will not compromise our core values of integrity, fairness, trust, and social responsibility. BILLINGS DENVER TULSA HOUSTON SHREVEPORT Proved Property Acquisitions ($ millions) 100 75 50 25 00 01 02 03 04 (budget) Reserves Per Share (MCFE) 20 15 10 5 99 00 01 02 03 Operations St. Mary operates in five core areas managed from four regional offices. The Mid-Continent, Rocky Mountain, ArkLaTex, Gulf Coast, and Permian Basin regions are operated out of our offices in Tulsa, Oklahoma; Billings, Montana; Shreveport, Louisiana; and Houston, Texas. Each office is staffed with a full complement of geologists/geophysisists, engineers, and landmen who have extensive experience in the region/basin where they work. Our Denver headquarters provides the administrative support and oversight for the regions. St. Mary will operate approximately 75% of its $173 million exploration and development capital expenditures budget in 2004. By operating such a large amount of our budget, we are able to maximize the benefit of our expertise in the land, geoscience, and engineering disciplines. In each core area, we focus on cautious detailed land and legal work, disciplined geologic interpretations, reservoir management, efficient completion and stimulation techniques, and the appropriate application of new technologies when warranted. Acquisitions The acquisition of oil and gas assets and companies is an important part of our growth strategy. We focus our attention on smaller niche acquisitions in existing core areas where we can utilize our geologic knowledge of the area, our technical engineering expertise, and our financial flexibility. At the same time, we are actively seeking larger acquisitions that would allow us to expand our existing core areas, acquire additional geoscientists, and/or gain significant interests in a new basin within the United States. In 2003, we spent $77.4 million on niche acquisitions of proved reserves, which represented 33% of our capital expenditures program. In 2004, we are budgeting $100 million for acquisitions, which is 37% of our budget. Over the last five years, we have completed $292.9 million of proved property acquisitions. Financial Strategies Through consistent economic growth in reserves and production, St. Mary’s objective is to increase per share value in excess of 15% per year. To achieve the objective, our goal is to economically replace, on average, 200% of our annual production and to have full cycle economics in the top quartile of our peer group. Over the past five years, we have replaced, on average, 274% of our production with excellent economics. From December 1992, when we first became a public company, through December 31, 2003, we have provided our stockholders, in dividends and stock value, a compounded rate of return of 16%. Our strategy is also to maintain a strong balance sheet by keeping our debt to capital ratio below 35%. A strong balance sheet allows us to weather cycles of low commodity prices and be opportunistic when capital is not available to our peers. We are willing to become aggressive and increase our debt to capital ratio during down cycles in order to make strategic acquisitions. FINANCIAL HIGHLIGHTS In thousands except production, price data, and per share, as adjusted for 2 for 1 split on 9/5/00 2003 2002 2001 2000 1999 Income Statement Data Oil and gas production revenues Gains on sales and other Total operating revenues Net income $ 365,114 28,820 $ 393,934 $ 95,575 $ 185,670 10,724 $ 196,394 $ 27,560 $ 203,973 3,496 $ 207,469 $ 40,459 $ 188,407 7,259 $ 195,666 $ 55,620 Diluted earnings per share $ 2.80 $ 0.97 $ 1.42 $ 1.97 Cash dividends declared and paid per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 73,387 1,527 $ 74,914 $ $ $ 82 0.00 0.10 Diluted weighted average common shares outstanding 35,534 28,391 28,555 28,271 22,329 Balance Sheet Data Working capital Total assets Long-term debt Stockholders’ equity Average Net Daily Production Gas (Mcf) Oil (Bbls) MCFE (6:1) Average Sales Price Gas (per Mcf) Oil (per Bbl) Reserves Gas (Mcf) Oil (Bbls) MCFE (6:1) $ 3,101 $ 2,050 $ 34,000 $ 40,639 $ 13,440 735,854 110,696 390,653 136,062 12,441 210,709 537,139 113,601 299,513 104,558 7,713 150,836 436,989 64,000 286,117 108,195 6,667 148,199 321,895 22,000 250,136 104,769 6,551 144,075 230,438 13,000 188,772 62,478 3,790 85,218 $ 4.89 $ 26.96 $ 3.00 $ 25.34 $ 3.73 $ 23.29 $ $ 3.44 23.53 $ $ 2.21 16.56 307,024 47,787 593,746 274,172 36,119 490,887 241,231 23,669 383,247 225,975 20,950 351,673 207,642 18,900 321,042 Shareholders’ Equity ($ millions) Reserve Growth (BCFE) Production Growth (Daily MMCFE) 400 300 200 100 600 450 300 150 250 200 150 100 50 99 00 01 02 03 99 00 01 02 03 99 00 01 02 03 04 (projected) 1 TO OUR SHAREHOLDERS The year 2003 represented almost the best of all worlds for the Company: record earnings, high oil and gas prices, a 40% increase in the Company’s production, a 21% increase in estimated proved reserves obtained at a low reserve replacement cost, moderate increases in operating costs, profitable sales of non- strategic assets, and advancement of the Hanging Woman Basin coalbed methane project to the development stage. What does this mean in terms of creating shareholder value? When comparing the December 31, 2002 balance sheet with the pro forma balance sheet at December 31, 2003, adjusted for the buy-back of 3.38 million shares from Flying J for $26.92 per share in February 2004, they are very similar. Long term debt net of working capital were essentially at the same levels and our shares outstanding increased by only 269,000 shares or 1%. However, our proved reserves increased by 21% to 594 BCFE. Our pretax SEC PV10 value for our proved reserves increased 55% to $1.278 billion reflecting the 21% increase in reserves as well as increased oil and gas prices. In addition, we added new estimated probable reserves at Hanging Woman of 147 BCFE. Highlights include good drilling results at Huxley in east Texas, Northeast Mayfield in Oklahoma, and participation in the new Bakken horizontal dolomite play in the Williston Basin; better than expected production performance at the Parkway Delaware waterflood project in the Permian Basin and at Judge Digby in south Louisiana; as well as increased production from the acquisition of properties in the Rockies from Flying J in January 2003 and Burlington Resources in December 2002. We opened a Houston office, which will now be directing our Gulf Coast and Permian Basin regional operations. The many corporate scandals over the last two years were the catalyst for new legislation and SEC and NYSE rules, which strengthened the requirements for good corporate governance. Not only did the new rules expand requirements regarding the Board’s responsibilities, procedures, and independence, they also require enhanced and accelerated disclosures, establishment of an internal audit function, CEO/CFO certifications, adoption of a code of business conduct and ethics, and shareholder approval of equity compensation plans. We have complied with these new rules and have begun implementing procedures for the upcoming accelerated 10K and 10Q filing framework and internal control reports for 2004. We received an “A” rating in corporate governance from the Corporate Library independent evaluation service. Net income for the year 2003 was a record $95.6 million or $2.80 per share compared to $27.6 million or $0.97 per share for the prior year. Net cash provided by operating activities increased 44% to $204.3 million. Production increased 40% to 77 BCFE. The average realized price increased 41% to $4.75 per MCFE. Unit costs increased modestly for the period as production expenses (including taxes) increased $0.23 to $1.15 per MCFE, DD&A (including impairments) increased $0.08 to $1.07 per MCFE, and general and administrative expense increased $0.07 to $0.33 per MCFE. Oil and gas reserves grew by 21% to 594 BCFE. We replaced 293% of our 2003 production at an all-inclusive finding cost of $1.05 per MCFE. Ryder Scott has been preparing estimates of our reserves for at least 80% of our total PV-10 value since we went public in 1992, and we continue to report a very low PUD 2 M A R K A . H E L L E R S T E I N • C H A I R M A N , P R E S I D E N T & C E O percentage, 11% at year-end. We are pleased with these results and believe they compare favorably with industry results. To grow net asset value per share, we set a goal to economically replace 200% of our annual production. We have successfully achieved this goal over time, providing our share- holders a 16% compounded return since going public in 1992. We enter 2004 on a positive note: • Oil and gas prices are high and the long-term outlook is positive. • We have an outstanding inventory of prospects to be drilled. • The country’s ability to supply gas remains challenging, as the average decline rate for natural gas production has increased from 17% to 28% over the past 13 years. • New sources of gas such as LNG, frontier regions (e.g. deepwater Gulf of Mexico, Mackenzie Delta, Alaska) and unconventional gas plays are both more costly and have long lead times, but at some point could have a positive impact on supply. • We believe oil prices are unusually high now due to low inventory levels. Longer term, however, we are beginning to see excess oil capacity in the world diminish, and OPEC informally appearing to target a higher price range due to the decline in the value of the dollar. • The U.S. and world economies appear to be recovering from the recent economic downturn, and as they continue to recover we anticipate the demand for oil and natural gas will increase. We enter the year 2004 in very good financial condition and with a capital expenditure budget of $273 million. Here is our plan to build value in 2004: at Trinidad SE, Bethany Longstreet, Dykesville, and Terryville. In addition, we have two wells planned at Judge Digby in the Gulf Coast as well as several wells in south Louisiana targeting attic locations. • We will begin development of our Hanging Woman Basin coalbed methane project with the drilling of approximately 100 wells in Wyoming, and the construction of infrastructure such as an electric grid and pipeline. We currently expect production of natural gas to begin in 2005. • We have received newly shot and processed 3-D seismic data covering our entire 25,000-acre fee land position in St. Mary Parish, Louisiana. This is the first time we have had 3-D seismic coverage over the entire property. Cumulative production from this fee acreage is approximately 3.5 TCF of gas and 200 million barrels of oil. We have optioned 14,969 acres for lease primarily in the middle portion of our property where little exploration has historically taken place. Providing the option is exercised, the lease terms will give us a 25% royalty interest and the option to participate for up to 25% as a working interest owner. We believe the 3-D seismic provides an opportunity to expose us to significant new reserve potential. Our annual report theme this year is “repeatability.” By definition our resource base is depleting every day. Sustainability in our business is dependent on people who have the ability to create new ideas and new value year after year. St. Mary has demonstrated over a long period of time its ability to grow value consistently and to periodically have an idea that moves us to another level of performance. We have learned that “large” ideas come in a variety of forms, from exploration to secondary recovery to opportunistic acquisition, and in a variety of regions. Examples include the successful Parkway Delaware waterflood project, Box Church, S. Horseshoe Bayou, King Ranch Energy, Flying J, and Northeast Mayfield. Our decentralized organization of talented geoscientists, engineers and landmen in each of our regional offices, backed by a strong balance sheet and discipline, has given us the formula for repeating success. Few companies have done this as well as St. Mary over an extended period of time. Ron Boone retired last year as Executive Vice President and Chief Operating Officer having served St. Mary for more than 13 years. He will continue his role as a director of the Company. Ron was instrumental in helping assemble the talent base, and instilling disciplined thinking and attention to detail that has helped build St. Mary into a highly respected public company. I am deeply appreciative to Ron for his outstanding contribution. Over the past two years, we have implemented a plan for succession that has resulted in very strong regional managers and the preparation of Ron’s successor, Doug York, who has served St. Mary as an executive officer over the past seven years. I have great confidence in this group and we embrace the challenge of repeatability on your behalf. March 5, 2004 Mark A. Hellerstein Chairman, President and Chief Executive Officer 3 Capital Expenditures ($ millions) 300 200 100 00 01 02 03 04 (budget) Operating Cash Flow ($ millions) 200 150 100 50 99 00 01 02 03 • • Production is currently forecasted to grow to 78-82 BCFE, up from 77 BCFE in 2003. Based on NYMEX strip prices of $30.19 per Bbl and $5.44 per Mcf, as of December 31, 2003, we would realize approximately $4.68 per MCFE, after hedges. Assuming this price deck, lease operating expenses, including taxes, are forecasted at $1.18-$1.25 per MCFE and G&A is forecasted at $0.32-$0.37 per MCFE. Of the $273 million capital expenditures budget, 36% is allocated for acquisitions, 22% for exploration and develop- ment in the Mid-Continent region, 19% in the Rocky Mountain region, 8% in the ArkLaTex region, 7% in the Gulf Coast region, and 4% in the Permian Basin region. Four percent of the budget is allocated to development of our Hanging Woman Basin coalbed methane play and other CBM projects. The drilling portion of the budget represents a 12% increase over 2003. The significant planned exploitation activity includes 32 wells at Northeast Mayfield, six wells in the Arkoma Basin, and six Granite Wash wells, all in Oklahoma. In the Rockies, we have budgeted eight operated Bakken wells, four operated Red River wells in the Williston Basin, and six operated wells in Wyoming at the Big Hand, Delaney Rim, Monument Lake, and West Madden fields, as well as 28 wells in the Greater Green River Basin that are mostly non-operated. In the Permian Basin, we have budgeted six infill locations at the Parkway Delaware waterflood project, four injection wells at the East Shugart waterflood project, seven Canyon wells, and participation in a number of non-operated wells. In the ArkLaTex region, we are planning to participate in 41 wells including eight horizontal James Lime wells in east Texas and north Louisiana, and 18 wells DOUGLAS W. YORK • EXECUTIVE VICE PRESIDENT AND CHIEF OPERATING OFFICER OPERATIONS St. Mary’s operations are a combination of exploration, exploitation, development, and acquisition of oil and gas properties in five core areas in the United States. Our five core areas — the Mid-Continent region, the Rocky Mountain region, the ArkLaTex region, the Gulf Coast region and the Permian Basin region — are operated out of four regional offices. Senior managers, each with more than 20 years of professional experience, head each regional office. Each office has a full complement of geoscientists, engineers, land professionals, and support personnel who typically have spent most of their careers in the basin or region where they are working. The regional offices are supported by centralized administration in our Denver office. This year was highlighted by excellent drilling results in Northeast Mayfield in the Anadarko Basin, successful horizontal exploitation of the James Lime formation in the Huxley field in east Texas, improving waterflood performance in the Permian Basin, and our participation in the horizontal Bakken play in the Williston Basin. In addition, we closed on $77.4 million of property acquisitions that added 113.0 BCFE of proved reserves and nearly 500,000 acres of undeveloped leases, which will provide future exploration, development, and exploitation opportunities. In 2003, we grew our production 40% to 76.9 BCFE, or an average daily production rate of 210.7 MMcfe per day. Net proved reserves at December 31, 2003 increased 21% to 593.7 BCFE, 89% proved developed, after we sold 45.6 BCFE of non-core 4 assets. Our reserve base at year-end 2003 was 52% natural gas and 48% oil. During 2003, we participated in drilling 181 wells with an 86% success rate. We are budgeting $273 million for capital expenditures in 2004. This represents an 18% increase over the $231 million spent in 2003. Exploration and development expenditures are projected to be $173 million and $100 million is budgeted for property acquisitions. We will operate approximately 75% of our capital expenditures budget in 2004. With our strong balance sheet, we are not limited by our $100 million budget in looking for acquisition opportunities. We will be actively sourcing and evaluating opportunities during 2004 for acquisitions that meet our economic parameters. We begin 2004 with the largest inventory of drilling prospects in the history of our Company. We continue to add experienced geoscientists, engineers, land professionals, and support personnel in each of our regions. Using the extensive proprietary databases we have compiled in each of our regions, our growing technical teams are able to increase their prospect generation capabilities. With offices in each region, we are aware of new plays and new ideas and are able to react quickly to activity in each of our core areas. The exploration and development programs that replaced 146% of our production through the drill bit in 2003 will continue in 2004. In 2004, we plan to drill more than double the number of wells we completed in 2003 in Northeast Mayfield in the Anadarko Basin, where we have not drilled a dry hole. Our horizontal exploitation of the James Lime formation in the ArkLaTex region moves to the Spider field in northern Louisiana, Reserve Base By Region Mid-Continent – 26% ArkLaTex – 11% Gulf – 6% Rocky Mountain – 49% Permian – 8% Capital Expenditures Budget By Region Mid-Continent – 22% ArkLaTex – 8% Gulf – 7% Rocky Mountain– 23% Permian – 4% Acquisitions – 37% (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) (cid:2) which is similar to but geologically more complex than the Huxley field we developed in 2003 in east Texas. We will be drilling several infill wells in the Parkway Delaware Unit waterflood and we anticipate production to continue to increase in the East Shugart waterflood in the Permian Basin where we saw a production response in 2003 to this significant secondary recovery project. Our participation in the horizontal Bakken play in the Williston Basin will increase significantly in 2004 as the activity moves toward our major lease holdings in the area. In addition, we will be participating in two new exciting opportunities with long-term potential. In early 2004, we received processed 3-D seismic data over our fee lands in St. Mary Parish, Louisiana. Our fee property has produced more than 200 million barrels of oil and 3.5 TCF of natural gas since the initial discoveries in 1938. This is the first time the middle portion of our property has been shot with 3-D seismic and the first time new 3-D has been shot since the early 1990s. We have optioned the unleased acres, which if exercised, provides us with a 25% royalty interest on any production from the property and the right to participate for up to a 25% working interest. This election is on a well-by-well basis. We believe there is not only a deep untested structure on the property, but shallow potential as well. In late 2003, we made a decision to proceed with our coalbed methane program in the Hanging Woman Basin, which is in the northern portion of the Powder River Basin in Montana and Wyoming. We have 139,000 acres of net leases in Montana and Wyoming and will begin development on the 65,000 net acres in Wyoming. We have estimated probable reserves of 147 BCFE from five of the coal seams and acreage in Wyoming. In addition, we believe there is significant potential in the coal seams and acreage we have not yet evaluated. We plan to begin drilling during the second quarter of 2004 with first production anticipated in early 2005. The locations for approximately 93% of our drilling expenditures in 2004 have been identified. Our major programs will extend well beyond 2004 on leases currently in our inventory. Our task in 2004, as it is every year, is to continue to develop prospects that will economically grow our reserves and production as we have done year after year. Following is additional information about the operations in each of our core areas and more detail of our plans for 2004. M I L A M R A N D O L P H P H A R O • V I C E P R E S I D E N T – L A N D A N D L E G A L ACQUISITIONS ARE PART OF OUR GROWTH St. Mary’s objective is to grow its per share net asset value in excess of 15% per year. If we consistently grow net asset value, our stock price will follow. The 16% compounded rate of return we have provided our stockholders in dividends and stock value over the past 11 years reflects the growth in net asset value we have achieved. Our growth has been a combination of organic growth through the drill bit (the exploration, development, and exploitation of our properties), property acquisitions, and the occasional divestiture of non-strategic assets in overheated markets. The synergies of exploration, development, and exploitation work with the synergies of acquisitions and divestitures. The technical expertise necessary to drill and exploit properties is the same expertise needed to evaluate acquisition opportunities. In addition to adding oil and gas reserves, acquisitions provide an inventory of exploration, exploitation, and development opportunities. Our goal is to replace, on average, 200% of our production, which approximately equates to a 15% growth rate in reserves. Our technical expertise and strong acreage positions have allowed us to economically replace, on average, approximately 100% to 115% of our annual production organically through the drill bit. Although our focus is to make acquisitions in our five core areas, we also consider acquisitions that will provide an entreé into new core areas. Niche acquisitions in our core areas allow us to utilize our technical expertise specific to the area and take advantage of operational efficiencies. Acquisitions outside our core areas will be made if we believe we can develop the technical expertise to grow the area. With a strong balance sheet and highly regarded stock, we have the financial capability to make significant acquisitions. Each year we allocate approximately 40% of our capital expenditures budget for acquisitions. In 2004 we have an acquisitions budget of $100 million. This is a goal, but not a limit as we have substantial unused financial capability. In the past, we have used our Company’s stock to make acquisitions and may use stock in the future if the acquisition is accretive to St. Mary on a net 5 asset value basis. Because of our strong balance sheet and historical record, we have the reputation of being able to close acquisitions, which can be a significant advantage in a highly competitive environment. The flexibility of being able to use either cash or stock or both, has enabled us to be creative in structuring acquisitions that are both accretive to St. Mary and responsive to the needs of the seller. An example is the acquisition of oil and gas properties from Flying J Oil & Gas Inc. and Big West Oil & Gas Inc. that closed in January 2003. In the transaction, we issued 3,380,818 restricted shares of St. Mary common stock, which represented 10% of our combined outstanding shares, for properties that represented 15% of our combined reserves at the time of negotiation and doubled our undeveloped leasehold inventory. To respond to the sellers’ need for cash, we lent them $71.6 million in the form of a note, and secured the note with the shares they received. To assure the sellers that they could exchange their shares in full payment of the note, we granted them the right to put their shares of St. Mary common stock to the Company as payment of the $71.6 million note ($21.18 per share) plus accrued interest for 30 months, and in return we were granted the right, during that same 30-month period, to redeem the St. Mary common stock they received for $28.82 per share. On a strictly stock-for-assets basis, the acquisition was clearly accretive to net asset value and other metrics. In February 2004, after substantial growth in our reserves, production, and net asset value, we repurchased the 3,380,818 common shares for a negotiated $26.92 per share. Again, the share repurchase is accretive to book value, earnings and EBITDAX per share and at the same time resulted in a good outcome to Flying J and Big West. Because natural gas properties have generally been selling at premiums that do not meet our return objectives, our recent acquisitions have been primarily oil properties. Oil properties have been less competitive, and we have been able to make acquisitions that fit within our disciplined evaluation standards. Our financial and evaluation criteria include acceptable returns from the producing properties and an opportunity to add value using our geologic concepts, reservoir management, and well completion and production techniques. We price our acquisitions using commodity strip pricing and generally hedge a minimum of the first two years of estimated production from the properties. We believe that by reducing commodity price risk, we are able to bid more aggressively and make acquisitions that fit our return objectives. In 2003, we closed on $77.4 million of acquisitions that added 113.0 BCFE of proved reserves. Over the past three years, we have closed $206.3 million of acquisitions that represent 34% of our capital expenditures. Also in 2003, we received proceeds of $23.5 million from the sale of non-core properties. We recorded a before-tax gain of $7.3 million from the sale of these properties. Rocky Mountain Region PROVED RESERVES % OF TOTAL RESERVES GAS / OIL MIX PROVED DEVELOPED RESERVES CAPITAL EXPENDITURES BUDGET: NON-CBM COALBED METHANE PROJECTS 290.1 BCFE 49% 22% / 78% 95% $51.7 MILLION $12.2 MILLION Nance Petroleum Corporation, a wholly owned subsidiary, manages our operations in the Rocky Mountain region, which now include our coalbed methane projects. Our Nance office in Billings, Montana currently has a 58-person staff. Nance has managed our interests in the Williston Basin since 1991, initially under a partnership arrangement and, since June 1, 1999 as a wholly owned subsidiary. Since 1999, the Nance office has also managed our interests in other Rocky Mountain Basins and the Permian Basin. In 2004 management of the Permian Basin was moved to our newly opened office in Houston, Texas. Our Rocky Mountain region includes the Williston Basin in eastern Montana and western North Dakota, the Powder River Basin in Montana and Wyoming, and the Greater Green River and Wind River Basins in Wyoming. The Williston Basin, where we have been a dominant operator since 1991, anchors our activity in the Rocky Mountain region. Our operations in the Powder River (excluding coalbed methane), Greater Green River, and Wind River Basins were primarily initiated through acquisitions made during the past three years. Our Hanging Woman Basin coalbed methane project initiated in 2001 is in the northern portion of the Powder River Basin. The Rocky Mountain region experienced significant growth in 2003. We closed the two largest acquisitions in the history of our company with the December 2002 acquisition from Burlington Resources and the January 2003 Flying J acquisition. These two acquisitions more than doubled our proved oil and gas reserves in the Rocky Mountain region, included a large undeveloped lease inventory, and provided numerous exploitation opportunities. During the first part of 2003, exploration and development activity in the Rocky Mountain region was delayed somewhat as the majority of our time was spent assimilating these new properties into our operations. In 2003, the Rocky Mountain region drilled and participated in 42 wells, of which 38, or 90%, were successful. At year-end, two wells were completing. The region spent $100.3 million, including $72.2 million for acquisitions, which represents 43% of our total capital expenditures in 2003. The 28.4 BCFE produced from the region was 37% of our total production. The Rocky Mountain region replaced 452% of its production in 2003. Since 1991, when we began operating in the Williston Basin, we have had a 92% drilling success rate. Our success rate is 6 largely attributable to our ability to identify and match structure and porosity development in the Red River formation using 3-D seismic. In 2003, we completed four 3-D seismic surveys in the Basin. Based on the 3-D results, we drilled the Steinbeisser 7-2 in the Ridgelawn field that had an initial production rate of 320 Bbls of oil per day and 1,000 Mcf of gas per day from the Red River. We have budgeted four additional wells in the Ridgelawn field in 2004. We are also planning to drill seven operated wells in other prospects in 2004, all based on 3-D seismic. We have included six 3-D seismic surveys in our capital expenditures budget in 2004. Primarily because of leasehold acreage acquired in the Burlington and Flying J acquisitions, we have a significant lease position in the horizontal Bakken dolomite play that has become the most active new play in the Williston Basin. We have approximately 22,000 leased acres in the fairway of this play, where wells are being drilled with initial rates of 250 to 650 Bbls per day and anticipated reserves of 350,000 to 750,000 barrels of oil equivalent. We drilled and participated in three horizontal Bakken wells. The wells were drilled in the dolomite section that lies 20 to 30 feet below the extensively drilled Bakken shale, which has been drilled extensively in the Basin. Acquired from Burlington Resources, the Strand 22-27H was a marginal well in which we own a 100% working interest and 100% net revenue interest. This well was producing from the Bakken shale. We reentered the Strand well bore and drilled a horizontal lateral in the Bakken dolomite, which increased production to 340 Bbls of oil per day. In 2003, we drilled two horizontal laterals from the Vaira 2-35H in the Bakken dolomite. Each lateral has tested at approximately 400 Bbls of oil per day. When combined, the well had an initial production rate of 650 Bbls of oil per day. On our leases we have identified 18 proven and probable locations for horizontal Bakken wells and have budgeted to drill or reenter wells on nine of the locations in 2004. With our lease position, the additional leases we control east of the current exploration WILLISTON BASIN HORIZONTAL BAKKEN DOLOMITE PLAY STRAND 22-27H VAIRA 2-35H BR 44x-1 2003 SUCCESSFUL NANCE WELLS SUCCESSFUL HORIZONTAL BAKKEN WELLS 2004 WELLS TO DRILL FUTURE IDENTIFIED LOCATIONS M ONTAN A NORTH DAKOTA 7 Rocky Mountain Capital Expenditures ($ millions) 100 75 50 25 00 01 02 03 04 (budget) Exploration & Development (cid:2) Acquisitions Rocky Mountain Proved Reserves (BCFE) 300 200 100 99 00 01 02 03 Rocky Mountain Technical Employees 99 00 01 02 03 40 30 20 10 8 (cid:2) area, and depending upon how far the Bakken dolomite play extends, we could be actively drilling wells in this area for the next two to three years or more. The $51.7 million capital expenditures budget in 2004 for the Rocky Mountain region (excluding the coalbed methane projects discussed in the following section) is an 83% increase over the $28.1 million spent for exploration and development drilling in 2003. Approximately 70% of the Rocky Mountain region budget has been allocated to the Williston Basin to drill the previously mentioned operated wells, wells anticipated to be proposed by other operators, recompletions, seismic, and land costs. The balance of the budget is planned for six operated wells in the Greater Green River, Wind River and Powder River Basins and 28 non-operated wells primarily in the Greater Green River Basin, along with seismic and land costs. We will operate approximately 79% of the Rocky Mountain capital expenditures budget (excluding the coalbed methane projects). Coalbed Methane Projects The Hanging Woman Basin is in the northern part of the Powder River Basin along the Montana-Wyoming border. Since our entry into the Basin in 2001, we have amassed a 139,000-acre net lease position over coalbed methane reserves. Using pilot projects that include 21 wells, extensive field geology, production analysis and economic modeling to evaluate the potential of the properties, we made a decision in November of 2003 to proceed with development of the reserves. There are 10 different coal seams present on our properties. Our initial evaluation has been focused on 65,000 of the acres in Wyoming and five of the 10 coal seams. We have estimated probable reserves of 147 BCF, net to our interest, from the Wyoming portion of these five seams. These are the Anderson, Canyon, Brewster/Arnold, Nance and Roberts coals. Our 2004 capital expenditures budget for the Hanging Woman Basin project is $11.0 million. The budget includes drilling and completing 108 wells and installing power lines and gathering facilities. Drilling is expected to begin during the second quarter of 2004. Gas production is expected to be minimal in 2004 and begin increasing in 2005. We anticipate drilling approximately 175 wells per year beginning in 2005. Based on 160-acre spacing units and assuming all wells are completed in separate coal seams (the coals are not commingled), there is potential for approximately 1,350 wells to be drilled on the 65,000 acres. The 139,000 total acres could include approximately 2,600 wells. We are also participating as a non-operator in the Atlantic Rim Doty Mountain and Jolly Roger coalbed methane projects in the Greater Green River Basin. For these projects in 2004, we have budgeted $1.2 million to participate in the drilling of 14 wells and for other associated costs. HANGING WOMAN BASIN COALBED METHANE PROJECT Nance Leases FIDELITY CX FIELD J.M. HUBER PRAIRIE DOG PROPOSED PENNACO I N E T O N O R T H E R N B O R D E R , N D E D B I S O N L P R O P O S A N D S L S S – G R A . I . B W . BIGHORN BITTER CREEK R I M R O C K 1 6 " Mid-Continent Region PROVED RESERVES % OF TOTAL RESERVES GAS / OIL MIX PROVED DEVELOPED RESERVES CAPITAL EXPENDITURES BUDGET 152.1 BCFE 26% 96% / 4% 85% $59.5 MILLION Our Mid-Continent region primarily includes our operations in the Anadarko and Arkoma Basins in Oklahoma and Texas. The region, where we have been operating since 1973, is managed out of our Tulsa, Oklahoma office by our 35-person staff. The Mid-Continent region was our most active drilling area in 2003. The region drilled and participated in 77 wells, of which 69 were successful, for a 90% success rate. The region spent $72.3 million, which represents 31% of our total capital expenditures in 2003. The 24.7 BCFE produced from the region was 32% of our total production. The Mid-Continent region replaced 120% of its production through drilling in 2003. The most active drilling area in the Mid-Continent region in 2003 was in western Oklahoma in our Northeast Mayfield prospect area. Our entry into the area was through a 1996 acquisition of one marginal well with interesting pressure performance that produced from the Crook sand below 19,000 feet. We believed the well was producing from a larger reservoir than was indicated from the marginal production. Subsequent wells in the prospect area confirmed our premise and led to our drilling 14 Crook sand wells, which were all completed as producers. As our activity in the area has increased, we have compiled a significant amount 9 (cid:2) (cid:2) of geologic data as the wells were drilled through the Morrow section where potential pay zones were logged and mapped. Consequently, the field has grown from a Crook sand play to a multi-sand play that has expanded each year since our 1996 acquisition. Our well economics have improved significantly with new fracture stimulation technology. The advent of multi-zone fracs and commingling production from multiple zones significantly improves the initial production rates that return our investment sooner. We have now produced from 18 Morrow pay intervals and have identified five to seven additional potential Morrow pay zones in Northeast Mayfield. These zones include the Hildebrand and Keathley sands in which prolific producers were completed in 1999. Due to the many wells drilled through the multiple Morrow zones looking for the Crook sand, we have been able to geologically map the irregular shaped sands, reducing the geologic risk of drilling for these uphole zones. In addition, in late 2002 we successfully tested the Atoka formation, which is a shallower zone than the Morrow sand interval. We have now identified five separate Atoka pays. Although not yet tested, from log analysis we believe there may also be Granite Wash potential in Northeast Mayfield. What began with the one well we acquired in 1996 has developed into one of the most active exploration plays in the Anadarko Basin and possibly the United States. We now have interests in 67 sections in the Mayfield area and may have the largest holdings in the play. We have drilled and completed 40 wells in Northeast Mayfield without a dry hole. We completed 16 of the 40 wells in 2003 and were completing six wells and drilling three more wells at year-end. We have budgeted 23 additional wells to be drilled in Northeast Mayfield in 2004 and have identified locations for each well. Our net production from Northeast Mayfield in 2003 increased to 9.6 BCFE from 3.7 BCFE in 2002. The more significant wells drilled in 2003 were the Dean 1-19 (53% St. Mary interest) that produced at an initial rate of 20,000 Mcf per day, the Dykes 1-17 (19% St. Mary interest) that produced at an initial rate of 20,600 Mcf per day, the Bess 1-26 (58% St. Mary interest) that produced at a rate of 14,300 Mcf per day, and the Heinsohn 4-36 (31% St. Mary interest) that produced at a rate of 12,500 Mcf per day. NORTHEAST MAYFIELD DRILLING PROGRAM (cid:127) 1997 WELLS (2) (cid:127) 2001 WELLS (6) (cid:127) 1998 WELLS (3) (cid:127) 2002 WELLS (10) (cid:127) 1999 WELLS (2) (cid:127) 2003 WELLS (13) (cid:127) 2000 WELLS (2) 2004 WELLS (23) As the drilling in Northeast Mayfield expands to the west, north, and south where we have the majority of our leasehold interest, and as completions and recompletions are made in new pay zones in the field, we anticipate being part of an increasing level of drilling activity in this area for several more years. In 2004, 55% of our Mid-Continent capital expenditures budget or $32.7 million is allocated to Northeast Mayfield. We were also active in the Oklahoma portion of the Arkoma Basin in 2003. During the year we added to our lease position and completed 11 wells with no dry holes. We have allocated $4.5 million of our 2004 capital expenditures budget to drill six wells targeting the Cromwell, Wapanucka, Spiro, and Oil Creek sands. In addition, we will be conducting a 20-square-mile 3-D seismic survey in the area to develop additional prospects in the McLish, Oil Creek, Viola, Cromwell, and Wapanucka zones. The balance of our $59.5 million Mid-Continent 2004 capital expenditures budget is being allocated to various prospects in the Anadarko Basin that we continue to develop and exploit. We are planning to spend $4.5 million to drill six Granite Wash wells, $3.7 million to drill two Morrow / Springer wells, $3.5 million for Atoka wells, and $2.4 million for seven Osborne / Red Fork / Cherokee wells. We plan to operate five to seven drilling rigs throughout the year and operate 71% of our capital expenditures budget. 10 (cid:1) Mid-Continent Capital Expenditures ($ millions) 80 60 40 20 00 01 02 03 04 (budget) Exploration & Development (cid:2) Acquisitions Mid-Continent Proved Reserves (BCFE) 160 120 80 40 99 00 01 02 03 Mid-Continent Technical Employees 25 20 15 10 5 99 00 01 02 03 11 (cid:2) ArkLaTex Capital Expenditures ($ millions) 25 20 15 10 5 00 01 02 03 04 (budget) Exploration & Development (cid:2) Acquisitions ArkLaTex Proved Reserves (BCFE) 75 50 25 99 00 01 02 03 ArkLaTex Technical Employees 15 10 5 99 00 01 02 03 12 (cid:2) ArkLaTex Region PROVED RESERVES % OF TOTAL RESERVES GAS / OIL MIX PROVED DEVELOPED RESERVES CAPITAL EXPENDITURES BUDGET 67.8 BCFE 11% 89% / 11% 80% $21.6 MILLION Our ArkLaTex region includes properties in east Texas, northern Louisiana, southern Arkansas, and southern Mississippi. Our 18-person office in Shreveport, Louisiana, manages the region where we have operated since 1992. The ArkLaTex region has grown through a combination of niche acquisitions, new field discoveries, and field extensions. The region has achieved significant growth and provided excellent economic returns by developing the untapped potential of Bayou D’Arbonne, Haynesville, Box Church, and more recently the Southeast Trinidad and Huxley fields. The ArkLaTex region had excellent drilling results in 2003. The region drilled and participated in 31 wells, of which 25 were successful, for an 81% success rate. At year-end, six wells were completing and one well was drilling. The region spent $25.1 million, which represents 11% of our total capital expenditures in 2003. The 7.1 BCFE produced from the region was 9% of our total production. The ArkLaTex region replaced 150% of its production in 2003, 139% through drilling. Our most active drilling in the ArkLaTex region in 2003 was in the Huxley field in east Texas on acreage acquired in 2002. The field produces from the fractured James Limestone at a depth of 6,200 feet. Horizontal drilling techniques have made this previously uneconomic trend a highly economic objective that stretches from DeSoto Parish, Louisiana to Nacogdoches County, Texas. At Huxley we have drilled two to three horizontal laterals from each surface location with each lateral extending as far as 8,000 feet. We completed five wells in the Huxley field in 2003 (St. Mary’s interest in each well is 81%) with an average initial production rate of 2,300 Mcf per day. At year-end, we were drilling one well and another well was completing. The wells provide good economics as the average completed well cost is approximately $1 million and per well reserves are estimated at 2.7 BCFE. We will be drilling one additional well in the Huxley field in 2004, which will complete development of the field. In 2003 we drilled our first well in the Spider field in Desoto Parish, Louisiana, which is northeast and across the Toledo Bend Reservoir from the east Texas Huxley field. This was the first horizontal James Lime completion in the Spider field, which is also part of the James Lime horizontal trend. The geology at Spider is more complex than at Huxley and will require drilling the horizontal laterals from each well in different configurations JAMES LIME HORIZONTAL TREND HUXLEY AND SPIDER FIELDS to maximize production and reserve potential. We plan to drill seven wells in the Spider field in 2004, which represents about 31% of our ArkLaTex drilling budget. The balance of our $21.6 million ArkLaTex 2004 capital expenditures budget is being allocated to a mix of exploratory and development projects in our prospect inventory. We plan to operate 81% of our ArkLaTex capital expenditures budget in 2004. Gulf Coast Region PROVED RESERVES % OF TOTAL RESERVES GAS / OIL MIX PROVED DEVELOPED RESERVES CAPITAL EXPENDITURES BUDGET 33.1 BCFE 5% 94% / 6% 94% $18.4 MILLION In February 2004, we closed our office in Lafayette, Louisiana, and moved the management of our Gulf Coast region to our newly opened office in Houston, Texas. At the same time, management of our Permian Basin assets was moved from our office in Billings, Montana, to Houston. We believe Houston will be a more central location to our operations and will assist in the growth of these two core areas. Our Gulf Coast region includes properties in the Gulf of Mexico and onshore in south Louisiana and south Texas. Our presence in south Louisiana dates back to the early 1900s when our founders acquired a franchise property in St. Mary Parish on the shoreline of the Gulf of Mexico. We have been receiving oil and gas royalty income from these 24,900 acres of fee lands since 1938. The fee lands represent a smaller portion of our company’s production each year but still yielded $4.6 million of oil and gas royalty revenue to St. Mary in 2003. The onshore Gulf Coast and Gulf of Mexico became a core area in 1999 with the acquisition of King Ranch Energy when we acquired producing and undeveloped properties along with 260,000 gross 13 Gulf/Permian Capital Expenditures ($ millions) 40 30 20 10 00 01 02 03 04 (budget) Exploration & Development (cid:2) Acquisitions Gulf/Permian Proved Reserves (BCFE) 125 100 75 50 25 99 00 01 02 03 Gulf/Permian Technical Employees 15 10 5 99 00 01 02 03 14 (cid:2) undeveloped acres and a large 3-D seismic database. The region contributed 17% of our production in 2003. The region is focused on development and exploitation opportunities. We continue to participate in the successful development of the Judge Digby field, although the field is nearing the end of new drilling. Our interest in the outside operated, ultra-deep field located in Point Coupe Parish outside Baton Rouge, Louisiana, which has produced more than 485 BCF of gas and 1.2 million Bbls of oil, ranges from 5% to 20% depending upon which of the 15 identified pay zones is producing. We have participated in seven new discoveries since acquiring our interest in the field in 1999. Approximately 29% of our $18.4 million budget for the Gulf region in 2004 is being allocated to Judge Digby. We plan to participate in drilling two new wells and the recompletion of several wells in 2004. As producing zones deplete, the wells are recompleted to the next uphole pay inter- val. Because of the multiple potential pay zones in each of the wells, we anticipate recompletion activity to continue in the Judge Digby field for many more years. In 2003, a seismic company conducted a single cohesive 3-D seismic survey over our 24,900-acre fee property. It was the first time the entire property had been included in a 3-D seismic survey. For allowing the survey on our property, we received a fee of $900,000 and were granted rights to the processed data. We also granted the seismic company the option to lease 14,900 acres that are currently available. If the option to lease is exercised, we will receive $250 per acre, a 25% mineral owner’s royalty, and the right to participate for up to a 25% working interest in any well drilled on the property. This election is on a spacing unit basis. Past 2-D seismic surveys conducted over these properties have indicated deep structures that could be productive in the Marge A and Rob chambersi sections. Since cumulative production from our fee property now exceeds 200 million Bbls of oil and 3.5 TCF of gas, newly defined 3-D structures could have significant potential to St. Mary, as we will have the opportunity to participate in new exploration in a very meaningful way. Permian Basin Region PROVED RESERVES % OF TOTAL RESERVES GAS / OIL MIX PROVED DEVELOPED RESERVES CAPITAL EXPENDITURES 50.6 BCFE 9% 13% / 87% 70% $10.0 MILLION Our Permian Basin region includes our properties in eastern New Mexico and western Texas. Our operations in the region range from exploration to exploitation to secondary recovery projects. Production in the Permian region increased 14% in 2003 primarily due to the January 2003 purchase of an additional BAYOU SALE FIELD WAX LAKE FIELD BELLE ISLE FIELD HORSESHOE BAYOU FIELD HBP LEASEHOLD OPTIONED L OUISIANA FEE LANDS 3-D SEISMIC SURVEY 50% interest in our Fort Chadbourne Odum Lime Unit and the improving performance of our two waterflood projects. Production at the Parkway Delaware Unit waterflood, which we initiated in 1999 when production was 450 Bbls per day, continues to increase. Production in 2003 was 1,250 Bbls per day, up 5% from 2002. Production at the East Shugart Delaware Unit waterflood, which is an analog to the Parkway Delaware Unit, increased 4% in 2003 as the formation began to respond to water injection. 34% of the Permian region’s $10.0 million 2004 capital expenditures budget is being allocated to six infill locations at Parkway, four injection wells at East Shugart, and various workover and recompletion efforts in these units. We will sell non-core assets when we are able to obtain a premium price in a high commodity price environment. In 2003, we sold various properties including the Fort Chadbourne Odum Lime Unit on that basis. Our initial ownership of Fort Chadbourne came as part of the 1999 King Ranch Energy acquisition. With its large well count, low production rates, and high operating costs, the unit becomes uneconomic in a low commodity price environment. For these reasons, Fort Chadbourne is a property we didn’t want to own for the long term, but we felt by obtaining operations, improving field production through drilling development wells, reworking existing wells, and obtaining additional interest in the field, we could enhance our value. As evidenced by our successful sale of this and other properties, this goal was accomplished. 15 (cid:2) (cid:2) DIRECTORS OFFICERS Mark A. Hellerstein Chairman, President and Chief Executive Officer Douglas W. York Executive Vice President and Chief Operating Officer Robert L. Nance Senior Vice President Jerry R. Schuyler Senior Vice President – General Manager, Gulf Coast Kevin E. Willson Senior Vice President – Mid-Continent, Drilling and Production Robert T. Hanley Vice President – Investor Relations and Management Reporting W. David Hart Vice President – Geology, ArkLaTex George M. Hearne IV Vice President – General Manager, ArkLaTex David W. Honeyfield Vice President – Finance, Treasurer and Secretary Milam Randolph Pharo Vice President – Land and Legal, Assistant Secretary Julian C. Pope Vice President – Mid-Continent, Land and Administration Assistant Secretary Garry A. Wilkening Vice President – Administration and Controller Linda A. Ditsworth Assistant Vice President – Land and Assistant Secretary Michael F. Roach Assistant Vice President – External Reporting Mark T. Solomon Assistant Vice President – Financial Reporting David J. Whitcomb Assistant Vice President – Gas Marketing Barbara M. Baumann Denver, Colorado President Cross Creek Energy Corporation Larry W. Bickle Houston, Texas Managing Director Haddington Ventures, L.L.C. Ronald D. Boone Denver, Colorado Former Executive Vice President and Chief Operating Officer St. Mary Land & Exploration Co. Thomas E. Congdon Denver, Colorado Former Chairman St. Mary Land & Exploration Co. William J. Gardiner Houston, Texas Chief Financial Officer King Ranch Inc. Mark A. Hellerstein Denver, Colorado Chairman, President and Chief Executive Officer St. Mary Land & Exploration Co. Arend J. Sandbulte Duluth, Minnesota Former Director and Chairman ALLETE, Inc. John M. Seidl San Francisco, California Chief Program Officer, Environment Gordon and Betty Moore Foundation 16 SHAREHOLDER INFORMATION INVESTOR SERVICES You can reach our corporate office at: St. Mary Land & Exploration Company 1776 Lincoln Street, Suite 700 Denver, CO 80203 303-861-8140 We also have offices in Tulsa, Oklahoma; Billings, Montana; Shreveport, Louisiana; and, Houston, Texas St. Mary Land & Exploration Company 7060 South Yale, Suite 800 Tulsa, OK 74136-5741 918-488-7600 St. Mary Land & Exploration Company 330 Marshall Street, Suite 1200 Shreveport, LA 71101 318-424-0804 Nance Petroleum Corporation 550 N. 31st Street, Suite 500 Billings, MT 59101 406-245-6248 St. Mary Land & Exploration Company 580 Westlake Park Blvd., Suite 600 Houston, TX 77079 281-677-2800 DESIGN BY: MARK MULVANY GRAPHIC DESIGN (DENVER, COLORADO) PHOTOGRAPHY BY: RON COPPOCK-KING (DENVER, COLORADO) INVESTOR RELATIONS CONTACT Stockholders, securities analysts or portfolio managers who have questions or need information concerning St. Mary may contact Bob Hanley, Vice President–Investor Relations and Management Reporting, at 303-863-4377. E-mail: bhanley@stmaryland.com Annual Reports, 10Ks, 10Qs To receive an information packet on St. Mary, or to be added to our mailing list, contact: Jim Robertson at 303-863-4322 E-mail: information@stmaryland.com Please visit our web site at: www.stmaryland.com Stock Transfer Agent Any stockholder with questions or inquiries regarding stock certificate holdings, changes in registration address, lost certificates, dividend payments and other stockholder account matters should be directed to St. Mary Land & Exploration Company’s transfer agent at the following address or phone number: Computershare Investor Services 350 Indiana Street, Suite 800 Golden, CO 80401 303-262-0600 NYSE: SM The Company’s common stock is listed for trading on the New York Stock Exchange under the symbol SM. The price ranges of the Company’s common stock by quarter for the last two years are provided below. As of February 20, 2004 the Company had 28,339,963 shares of common stock outstanding. Market Prices 2003— Quarter Ended 2002— Quarter Ended March 31 June 30 September 30 December 31 high low high low $27.23 $23.80 $23.25 $18.75 29.75 28.85 29.19 24.65 24.45 24.45 25.05 24.71 27.35 21.00 19.00 23.16 St. Mary Land & Exploration Company 1776 Lincoln Street Suite 700 Denver, Colorado 80203 Telephone: (303) 861-8140 Fax: (303) 861-0934 Internet: www.stmaryland.com 

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