SM Energy Company
Annual Report 2004

Plain-text annual report

Growing Through Competitive Advantages A N N U A L R E P O R T 2 0 0 4 FINANCIAL HIGHLIGHTS In thousands except production, price data, and per share Income Statement Data Oil and gas production revenues Gains on sales and other Total operating revenues Net income 2004 2003 2002 2001 2000 $ 413,318 19,781 $ 433,099 $ 92,479 $ 365,114 28,594 $ 393,708 $ 95,575 $ 185,670 10,635 $ 196,305 $ 27,560 $ 203,973 $ 188,407 3,496 $ 207,469 $ 40,459 7,259 $ 195,666 $ 55,620 Diluted earnings per share $ 2.88 $ 2.80 $ 0.97 $ 1.42 $ 1.97 Cash dividends declared and paid per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10 Diluted weighted average common shares outstanding 33,447 35,534 28,391 28,555 28,271 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) $ 12,035 $ 3,101 $ 2,050 $ 34,000 $ 40,639 945,460 136,791 484,455 127,316 13,113 205,992 735,854 110,696 390,653 136,062 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 $ 5.52 $ 32.53 $ 4.89 $ 26.96 $ 3.00 $ 25.34 $ 3.73 $ 23.29 $ $ 3.44 23.53 319,196 56,574 658,638 307,024 47,787 593,744 274,172 36,119 490,887 241,231 23,669 383,247 225,975 20,950 351,673 Shareholders’ Equity ($ millions) Proved Oil & Gas Reserves (BCFE) Oil & Gas Production Per Day (MMCFE) 500 400 300 200 100 750 600 450 300 150 250 200 150 100 50 00 01 02 03 04 00 01 02 03 04 00 01 02 03 04 05 (projected) Oil & Gas Production Per Share (MCFE) Operating Cash Flow (000’s) Capital Expenditures ($ Millions) 3.0 2.5 2.0 1.5 1.0 0.5 250 200 150 100 50 500 400 300 200 100 00 01 02 03 04 00 01 02 03 04 00 01 02 03 04 05 (budget) 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. OPERATIONS We operate 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/ geophysicists, engineers, and landmen who have extensive experi- ence in the region/basin where they work. Our Denver headquarters provides the administrative support and oversight for the regions. We will operate approximately 71% of our $293 million exploration and development capital expenditures budget in 2005. By operating such a large amount of our budget, we are able to maximize the benefit of our expertise in the land, geoscience, and engineering disciplines. In each core area, we focus on cautious detailed land and legal work, disciplined geologic interpretations, reservoir management, efficient completion and stimulation techniques, and the appropriate application of new technologies when warranted. ACQUISITIONS BILLINGS Greater Green River Basin Williston Basin Hanging Woman Basin Powder River Basin Wind River Basin DENVER Anadarko Basin TULSA Permian Basin Arkoma Basin ArkLaTex SHREVEPORT HOUSTON Gulf Coast The acquisition of oil and gas assets and companies is an important part of our growth strategy. We focus our attention on acquisitions in existing core areas where we can utilize our geologic knowledge of the area, our technical engineering expertise, and our financial flexibility. Property Acquisitions ($ millions) At the same time, we are actively seeking larger acquisitions that would allow us to expand our existing 125 100 75 50 25 core areas, acquire additional geoscientists, and/or gain significant interests in a new basin within the United States. In 2004, we spent $76.7 million on acquisitions, which represented 24% of our capital expenditures program. In 2005, we are budgeting $125 million for acquisitions, which is 30% of our budget. Over the last 01 02 03 04 05 (budget) five years, we have completed $336.5 million of property acquisitions. FINANCIAL STRATEG IES 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 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, 228% of our production with excellent economics. From December 1992, when we first became a public company, through December 31, 2004, we have provided our stockholders, in dividends and stock value, Proved Oil & Gas Reserves Per Share (MCFE) 25 20 15 10 5 a compounded rate of return of 18%. 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. At December 31, 2004, we have a debt 00 01 02 03 04 to capital ratio of 22%. Creating Competitive Advantages Our continued growth is dependent upon establishing competitive advantages. We must continually ask ourselves why assets are worth more to us than they are to our competitors. When we can answer that question, new economic opportunities will come our way. Competitive advantages provide the answer to the question and the edge we need to create value. Growing through competitive advantages is a work in progress that will never be completed. It is similar to a puzzle. Each puzzle piece represents a competitive COMP ETIT IVE ADVANTAGE S Corporate Strong Balance Sheet We keep our debt to capital ratio at 35% or less. A strong balance sheet allows us to be opportunistic and maintain consistent exploration and development programs from year to year. advantage. When our competitive edge becomes Financial Discipline dominant in a region or play, our economic opportunities will grow rapidly. But each play is discreet and the competition intense. Therefore, we must continually establish new competitive strengths, which will be the springboard for new growth. We believe we must add value at every phase of our business. Our annual report discusses some of the competitive advantages that we have identified throughout our company. Our job is to capitalize on these strengths to grow value and to create additional competitive advantages as we grow. All capital expenditures must meet minimum internal rate of return objectives. Corporate acquisitions must be accretive to our net asset value. Monthly, quarterly and annually we continually compare our results to our expectations in order to assure that our performance criteria are being met. 1 To Our Shareholders The year 2004 was highlighted by high oil and gas prices and record earnings per share; return on capital employed of 23%; a very competitive acquisition market; growing rig count and escalating costs; reasonable drilling results; a modest drop in production after increasing 40% the prior year; and commencement of development and first production at the Hanging Woman Basin coalbed methane project. We completed $76.7 million of acquisitions in 2004 and grew our reserve base by 11% and our pre-tax PV10 value of proved reserves by 17% to $1.5 billion. We repurchased 3.9 million shares of St. Mary stock at an average price of $27.73 per share, while we saw our stock price increase 46% for the year to $41.74 per share at December 31, 2004. Reserves per share grew 23% to 23.1 MCFE per outstanding share. Highlights in 2004 include excellent drilling results in the horizontal middle Bakken play in the Williston Basin where we participated in the drilling and completion of 15 wells with 100% success. New grassroots completed dual lateral wells drilled in Richland County, Montana cost approximately $2.7 million, with initial production rates of 350 to 600 Bbls of oil per day and proved reserves of approximately 350 to 500 MBbl, which results in outstanding economics. At year-end we had 45 proved undeveloped and probable locations identified in Montana and North Dakota. We have begun to test the play in North Dakota via re-entry of existing well bores with single lateral completions which cost approximately 40% of a grassroots dual lateral well. The middle Bakken dolomite thins as it moves southeast into North Dakota. Our initial results in North Dakota have been encouraging with unstimulated flow rates of 150 to 300 BOE per day. We have approximately 80,000 net acres in the middle Bakken fairway. We had several outstanding individual well completions in 2004. The Paggi Broussard #1 (40% working interest) is currently producing 31.2 MMCFE per day and the Vermillion 273 B3 (50% working interest), which initially produced approximately 15 MMCFE per day, is currently producing 11 MMCFE per day. The M C Delambre #1 at Judge Digby had an initial rate from the C-1 pay interval with 15 feet of pay (7.84% working interest) of 15.4 MMCFE per day with 140 feet of pay yet to be completed in the B zones (11.5% working interest). We also have had continued success in our Red River play in the Williston Basin as well as tight horizontal plays in the ArkLaTex region, including Huxley, Spider, Driscoll and Walkers Chapel fields, and growing activity in the Greater Green River Basin. We began development of our Hanging Woman Basin coalbed methane project by completing 57 wells in 2004. The pipeline and compression facilities were completed in December 2004 when we began selling our first gas. Netherland, Sewell and Associates, Inc. completed a comprehensive geologic and engineering study of this project, with an estimate of reserves as follows: HANGING WOMAN BASIN RESERVES 8,159 MMCF Proved 69,661 MMCF Probable 644,687 MMCF Possible 722,507 MMCF Total Probable and possible reserves have inherently more risk than proved reserves due to the fact that such well locations are either not direct offsets to existing wells or represent coal seams that have not yet produced in commercial quantities. In addition, permitting and timing of development activities cannot always be accurately estimated. Numerous shallow and intermediate depth coals have been successfully developed in the northern Powder River Basin. The deeper coals are estimated to contain significant gas reserves, but they have not yet been successfully developed in other projects. These deeper coals represent approximately 51% of the total proved, probable and possible reserves. Net income for the year 2004 was $92.5 million or $2.88 per share compared to $95.6 million or $2.80 per share for the prior year. Net cash provided by operating activities increased 16% to $237.2 million. Production decreased 2% to 75.4 BCFE. The average realized price increased 15% to $5.48 per MCFE. Unit costs increased modestly for the year as lease operating expense (includ- ing taxes) increased $0.12 to $1.27 per MCFE, DD&A (including impairments) increased $0.15 to $1.22 per MCFE and general and administrative expense increased $0.01 to $0.29 per MCFE. Proved oil and gas reserves grew by 11% to 659 BCFE. We replaced 190% of our 2004 production at an all-inclusive finding cost of $2.19 per MCFE. We continue to report a very low PUD percentage of 15% at year-end, despite maintaining a large 1.1 million net acre land position, of which 69% or 742,000 net acres are undeveloped. 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 shareholders an 18% compounded return since going public in 1992. MARK A. HELLERSTEIN CHAIRMAN, PRESIDENT & CEO Innovative Deal Structures: We are creative in structuring acquisitions to meet the financial and tax requirements of the seller and also meet our internal rate of return objectives. We have been successful structuring “win-win” arrangements that have added value for our shareholders. 2 We enter 2005 on a positive note: • We are in excellent financial condition. Incentive Programs That Match Performance • Oil and gas prices are high and the long-term outlook is positive. • We have an outstanding inventory of prospects to be drilled with multi-year plays in the Bakken and Red River formations in the Williston Basin, Northeast Mayfield in the Anadarko Basin and the Hanging Woman Basin. • We have increased our total capital expenditures budget to $418 million. Here is our plan to build value in 2005: • Production is currently forecast to grow to 81-85 BCFE, up from 75 BCFE in 2004. Based on NYMEX strip prices of $46.73 per Bbl and $6.26 per Mcf, we would realize approximately $6.56 per MCFE, after hedges. Lease operating expenses, including taxes, are currently forecast at $1.37– $1.47 per MCFE, G&A is forecast at $0.30 – $0.35 per MCFE and DD&A is forecast at $1.35– $1.45 per MCFE. • Of the $418 million budget, 30% is allocated for acquisitions, 23% for exploration and development in the Rocky Mountain region, 21% in the Mid-Continent region, 10% in the Gulf Coast region, 8% in the ArkLaTex region, 6% for our Hanging Woman Basin coalbed methane play and other coalbed methane projects and 2% in the Permian Basin region. We completed the acquisition of Agate Petroleum, Inc. in early 2005 recording approximately $42 million to oil and gas properties. The drilling portion of our budget is up $56 million representing a 24% increase over 2004. The Rocky Mountain region’s budget is up $30 million resulting from our success in the horizontal middle Bakken play and acceleration of activity in the Red River as well as the Greater Green River Basin plays. The Hanging Woman Basin coalbed methane budget more than doubled to $24.5 million. The ArkLaTex region’s budget is up $6 million due to drilling at the Elm Grove field where we acquired an interest through the Border Company acquisition in 2004. The Gulf Coast region’s budget is up $5 million as our Houston office expands our activity to not only include South Louisiana, but South and Southeast Texas and the outer continental shelf, including intermediate deep water. Approximately 80% of the Gulf Coast region’s budget will be for low to moderate risk exploration based either on direct hydrocarbon indicators or attic locations. The Mid-Continent region’s budget is down $10 million as Northeast Mayfield and our Granite Wash plays are high graded. We are seeing rig and other service costs increase and are experiencing rig shortages in certain areas. Therefore, our plan for 2005 will need to be flexible to a changing environment. Our annual report theme this year is “Growing through Competitive Advantage”. Our ability to grow St. Mary profitably is dependent on our ability to answer the question, “Why are assets worth more in our hands than in someone else’s?” We believe the answer to this question begins at the core of St. Mary: its value systems; its risk / reward profile; its incentive programs that help us attract, motivate and retain top talent; and its reporting and feedback systems which help us understand our business better. At the regional level, the answer may lie in better application of 3-D seismic and geologic knowledge; a large and strategic acreage position; the ability to apply new technologies and judgment to drill and stimulate wells more effectively and at lower cost; the ability to market our oil and gas at a premium over others; our ability to operate at a lower cost; or obtain financing at a lower cost. It also takes a combination of talent, creativity, focus, attention to detail and proper application of technology. In each of our regions we strive to establish clear competitive advantages. Once we have a substantial competitive edge, we believe opportunities will follow. Our business is quite competitive and the discreet nature of our asset base suggests that advantages do not last forever. Therefore, we are facing an ongoing struggle for that competitive edge. The battle never ends. We are proud of what we have accomplished. In this annual report, we will illustrate some of our key competitive advantages that have helped us become the 9th Best Small Pubic Company in America in 2004 according to Forbes’ magazine. March 11, 2005 Mark A. Hellerstein Chairman, President and Chief Executive Officer Incentive compensation under our cash bonus and restricted stock plans is based on the growth of St. Mary’s net asset value. Minimum growth objectives must be met before this performance-based compensation is earned. Our net profit pool incentive plan is designed to reward selected employees with a portion of cash flow from a pool once St. Mary has recovered 100% of its costs. It is a unique program that creates the proper tension between growth and economics. Because all participants are in the same pool, there is pressure for capital to flow to the most attractive investments. Because participants have a vested interest in the performance of the producing wells, they will not only focus on performance during the drilling phase, but throughout the life of the well. We Don’t Destroy Value Oil and gas exploration is a risk business and dry holes are inevitable. We manage our risk by focusing on low to moderate risk drilling, with a small portion of our budget available for higher risk / higher reward projects. By combining superior people with many years of experience in their region, attention to detail, focus and performance feedback, we have learned not to make big mistakes. Major successes can only have a big impact when other activities have not destroyed value. 3 Operations Overview We made significant progress this year building an inventory of multi-year exploration and development programs. An objective in each of our regions is to develop and use competitive advantages to identify opportunities that will create multi-year programs. Our participation in the horizontal middle Bakken play in the Williston Basin expanded into such a program in 2004. From three wells completed in 2003 to 15 completed wells in 2004 and plans for 30 wells in 2005, we continue to define the potential of the play and the technology that will allow us to extract maximum value from the play. We have not drilled a dry hole and have identified 45 proved undeveloped and probable drilling locations at year-end 2004. We have additional drilling locations identified in the possible category in our approximate 80,000 net acres of leases in the area we have defined as the middle Bakken fairway. We began development of our Hanging Woman Basin coalbed methane play in 2004 with 57 wells completed at year-end. The natural gas pipeline that connects the project area with the sales line was completed in mid-December 2004. Although the completed wells are in the dewatering phase, we did have gas production prior to year-end, which is encouraging. We plan to drill 150 wells in 2005 and have approximately 2,000 potential locations on the 154,000 net acres we have leased in the play. Northeast Mayfield in the Anadarko Basin continues to be an active drilling program. Results in 2004 failed to meet our expectations as we stepped out and drilled a number of wells in order to define the limits of the play. We completed 24 of the 28 wells drilled in 2004 and have identified 60 proved undeveloped and probable drilling locations at year-end 2004. We plan to drill 27 wells in Northeast Mayfield in 2005. Despite a very competitive acquisition market in 2004, we closed $76.7 million of property acquisitions that added 52.3 BCFE of proved and 22.6 BCFE of probable reserves. In addition, in January 2005 we closed on the acquisition of Agate Petroleum, Inc. with approximately $42 million allocated to oil and gas properties that adds 23.1 BCFE of proved and 5.8 BCFE of probable reserves in the Williston and Arkoma Basins. Net proved reserves at December 31, 2004 increased 11% to 658.6 BCFE, of which 85% are classified as proved developed. Our reserve base at year-end 2004 was 52% oil and 48% natural gas. During 2004, we participated in drilling 204 conventional wells with a 90% success rate. We also participated in drilling 83 coalbed methane wells during 2004. We are budgeting $418 million for capital expenditures in 2005. This amount represents a 34% increase over the $313 million spent in 2004. Exploration and development expenditures are projected to be $293 million and $125 million is budgeted for property acquisitions. We will operate approximately 71% of our capital expenditures budget in 2005. With our strong balance sheet, we are not limited by our $125 million budget in looking for acquisition opportunities. We will be actively sourcing and evaluating opportunities during 2005 for acquisitions that meet our economic parameters. We begin 2005 with the largest inventory of drilling prospects in the history of our Company including several multi-year plays. We have a large land inventory with 1,072,000 net acres, 69% of which are undeveloped. We continue to add experienced geoscientists, engineers, land professionals, and support personnel in each of our regional offices. With a local presence 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. Following is additional information about the operations in each of our core areas and more detail of our plans for 2005. DOUGLAS W. YORK EXECUTIVE VICE PRESIDENT AND CHIEF OPERATING OFFICER Capital Expenditures Budget By Region 21% 8% 10% 30% 6% 2% 23% n Mid-Continent n ArkLaTex n Gulf n Rocky Mountain n Coal Bed Methane n Permian n Acquisitions Reserve Base By Region 1% 7% 21% 54% 12% 5% 4 ROCKY MOUNTAIN REGI ON PROV ED RESERVES % OF TOTAL RESERVES GAS/OIL MIX PROV ED DEVELOP ED R ESE R VES TOTAL NET LEA SED ACR ES NET UNDEVELOPED LEA SED AC RE S CAP ITA L EXPENDI TUR ES BUD GE T: N O N C B M C OA LB ED ME TH AN E PR OJECT S COMP ETIT IVE ADVANTAGE S Rocky Mountain Region 3-D Seismic 36 5. 4 BCF E 55% 23 % / 7 7% 86% 83 9, 000 80% $ 94. 7 MIL LION $2 5 .8 MILLIO N Nance Petroleum Corporation, a wholly owned subsidiary, manages our operations in the Rocky Mountain region, which include our coalbed methane projects. Our Nance office in Billings, Montana currently has a 75-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. 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, Wind River and Big Horn Basins in Wyoming. 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 2004. The horizontal middle Bakken play in the Williston Basin has provided much of the growth. Our participation in the play has grown from completing three wells in 2003 to completing 15 wells in 2004 and budgeting 30 wells in 2005. The play that began in Richland County, Montana has crossed the state boundary into North Dakota where we have recently re-entered four existing well bores with encouraging results. During 2004 we conducted extensive geologic studies to define the middle Bakken fairway. Within the identified fairway, we have approximately 80,000 net acres (25,000 in Montana and 55,000 in North Dakota). At year-end 2004 we had two drilling rigs and two re-entry rigs drilling in the play and plan to add a third drilling rig during 2005. We continue to be active drilling wells to the Red River formation in the Williston Basin. Our 86% success rate since 1991 drilling wells in the Williston Basin is largely attributable to our ability to identify and match structure and porosity development using 3-D seismic. In In the Williston Basin we are able to map porosity development in the Red River formation using 3-D seismic imaging. Our technical ability has resulted in a 86% drilling success rate and has allowed us to be a consolidator of properties in the Williston. 5 Large Acreage Position Opportunities come to those owning oil and gas leases in the right place at the right time. Because of our large acreage position in the Williston Basin, we are a major partic- ipant in the horizontal middle Bakken play that currently is one of the more active plays in the Rockies. 6 2004 we completed four 3-D seismic surveys and have budgeted seven such surveys in 2005. We plan to drill nine Red River wells in 2005. Our activity in the Greater Green River, Wind River and Powder River Basins continues to grow. In 2005 we plan to participate in eight operated and 27 non-operated wells in the Wamsutter area of the Greater Green River Basin. The acquisition of Goldmark Engineering, Inc. in November 2004 included the Fourbear field in Park County, Wyoming. An active development program of the field will begin in 2005 with the drilling of three infill wells and the workover of numerous wells. In 2004, the Rocky Mountain region (excluding the coalbed methane programs) drilled and participated in 51 wells, of which 48, or 94%, were successful. The region spent $98.3 million, including $34.0 million for acquisitions, which represents 32% of our total capital expenditures in 2004. The 31.1 BCFE produced from the region was 41% of our total company production. Coalbed Methane Projects Development of our Hanging Woman Basin acreage in the northern portion of the Powder River Basin, along the Montana-Wyoming border, began in 2004. We completed 57 wells in the Anderson, Canyon and Cook coal seams. The wells are currently dewatering the coal seams and natural gas is being delivered to sales. We are completing wells using multiple coal seam completion techniques, which should greatly improve the economics of the play. A pipeline has been built into the project area connecting the program to several natural gas markets. Natural gas from the project area can be transported north into either the Northern Border system or the Williston Basin Interstate system. Natural gas can also be transported south to Glenrock, Wyoming where it can be sold into various Mid-Continent markets. Our 2005 capital expenditures budget for the Hanging Woman Basin project is $24.5 million. The budget includes drilling and completing 150 wells along with additional lease acquisition costs. The project has the potential to include as many as 2,000 wells on our 154,000-acre net lease position. We are also participating as a non-operator in Atlantic Rim coalbed methane projects in the Greater Green River Basin. We have budgeted $1.4 million for these projects in 2004 to participate in the drilling of 33 wells. M I D D L E B A K K E N P L AY Technology Leader in Horizontal Middle Bakken Play C U R R E N T A C R E A G E P O S I T I O N MONTANA GROSS 76,000 NET 48,000 NORTH DAKOTA 203,000 133,000 TOTAL 279,000 181,000 BAKKEN TREND 107,000 80,000 R IC H LA ND CO UN TY M O N T A N A B A K KEN FA IR WAY ACTIVI TY PRODUCING WELL P UD LOC ATION P ROB LO CATION N O R T H D A K O T A McK EN ZIE CO UN TY BI LL ING S CO UNT Y The horizontal Middle Bakken play is the most active play in the Williston Basin, and one of the more active plays in the U.S. It is located in Richland County, Montana and Billings and McKenzie Counties, North Dakota. Although we did not initiate this play, our tremendous HBP (“Held by Production”) acreage position allowed us to monitor the efforts of several private companies who applied new horizontal drilling and fracturing technologies to the middle Bakken. Once they were successfully completing horizontal wells in the middle Bakken, we were able to capitalize on our acreage position, which we believe to be the largest position held by a public company in the play. Our tremendous Rocky Mountain acreage position represents a key strategic advantage for the Company and did not happen by accident. It began with our proprietary ability to map both structure and porosity in the Red River formation allowing us to realize an 86% success rate since 1991. Our success allowed us to be competitive acquiring assets from companies that were exiting the Basin, at least partially, because they had not been able to achieve repeatable success exploring in the Red River. Since 2001 we have made the following acquisitions: Choctaw II Oil & Gas, Ltd. Burlington Resources Oil & Gas Company L.P. Flying J Oil & Gas, Inc. and Big West Oil & Gas, Inc. Agate Petroleum, Inc. 2001 2002 2003 2005 These acquisitions came with developed and undeveloped oil and gas leases throughout the Williston Basin (and other basins in the Rockies), including leases in Richland County, Montana and Billings and McKenzie Counties, North Dakota. Although initial drilling in the middle Bakken began in 2001, the play became active in 2003. With wells producing at initial rates of 300 to 600 barrels of oil per day and reserves per well estimated from 350,000 barrels to 500,000 barrels of oil, leases became very expensive and made it difficult for new companies to enter the play. We have accumulated 181,000 net acres of leases in the three counties where the middle Bakken is currently being explored and developed. Within our interpretation of the middle Bakken fairway, we have 80,000 net leased acres. From drilling dual laterals to open hole fracs, we are applying technology to the play. With each new well we are refining our techniques to enhance well productivity. Higher Oil Price Realization We bid out our oil production frequently. Because we are a major producer in the Williston Basin we are able to attract competing offers. Indexing the price of our oil to NYMEX and conducting the bidding process at selected times each year have resulted in higher oil price realizations than are received by our competitors in the Basin. 7 CO MPETITIVE ADVANTAGES Hanging Woman Basin Large Acreage Position H A N G I N G W O M A N B A S I N Fidelity CX Field Fidelity CX Field Expansion . I . B W . SHERIDAN J.M. Huber & Pennaco Prarie Dog W . B . I . C M S Proposed J.M. Huber & Pennaco Nance 2004 Development Area Nance 2005 Development Area Pinnacle M O N T A N A W Y O M I N G 6 " G R A S S L A N D S 1 – W . B . I . B I T T E R C R E E K Continental/Wolverine 1 2 " C M S 20" Pennaco Gibbs W E S T E R N G A S BITTER CREEK 16" 12" 16" R I M R O C K J.M. Huber & CH4 LX Bar T H U N D E R C R E E K Over the years we have consistently allocated 10% to 15% of our capital expenditures budget for higher risk, higher potential exploration ideas, non- conventional exploration and opportunistic acquisitions. In 2000, we used these funds to option approximately 70,000 acres of leases over coalbed methane reserves in the Hanging Woman Basin, located in the northern portion of the Powder River Basin. We believed the area had the potential to become a legacy asset of the company. After initial studies, in 2001 we exercised our option to lease and obtained additional leases that increased our holdings in the area. We hired and developed the technical expertise to evaluate the project and conducted two pilot well programs during 2002. After extensive study and modeling of the project using the results of our pilot projects and two existing coalbed methane programs operating west of our project area, we made the decision in 2003 to proceed with development. In 2004 we completed 57 wells and have budgeted to complete 150 wells in 2005, out of the potential 2,000 well locations on our 154,000 net acre lease position. We now have a major project that will be developed over many years. Once the wells have been dewatered, which is estimated to take nine to 18 months per well, the program is expected to provide a base of production for many years. The program continues to have the potential to be a legacy asset of the company. In our Hanging Woman Basin program, we have developed competitive advantages. Our large, mostly contiguous lease position allows us to develop the properties in an efficient, orderly manner. Because of the contiguous lease posi- tion, we are able to space wells on 160 acres rather than 80 acres, which improves economics and minimizes the environmental impact. Our technical expertise has developed multi-seam completion techniques that will reduce the number of wells necessary to develop the properties and will improve economics. We have added shareholder value by acquiring a large lease position over coalbed reserves, building the technical expertise to evaluate the properties and building the team to operate a multi-well, multi-year development program. Our large, mostly contiguous lease position allows for the efficient development of our coalbed reserves on 160 acre spacing rather than 80 acre spacing. Wells are spaced to maximize our economic return rather than to protect our position from being drained by others. Project facilities are scaled for maximum efficiency. Technical Expertise in Coalbed Natural Gas From geology to land to engineering to operations, we have assembled a superior technical team. Developing the technology to complete multiple coal seams in the same well bore significantly improves economics and minimizes environmental impact. Legacy Asset With approximately 2,000 well locations, we plan to develop the Hanging Woman Basin program over many years. The program is expected to provide a place to economically deploy capital and create a growing production base. 8 MID-CONTINENT REGION PROV ED RESERVES % OF TOTAL RESERVES GAS/OIL MIX PROV ED DEVELOP ED R ESE R VES TOTAL NET LEA SED ACR ES NET UNDEVELOPED LEA SED AC RE S CAP ITA L EXPENDI TUR ES BUD GE T COMP ETIT IVE ADVANTAGE S Mid-Continent Region Land Expertise 13 5. 7 BCF E 21% 95 % / 5 % 88% 93 ,0 00 29% $87 .0 MILL IO N 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 42-person staff. The Mid-Continent region continues to be our most active drilling core area. In 2004 the region drilled and participated in 108 wells, of which 98 were successful for a 91% success rate. The region spent $104.0 million, which represents 33% of our total capital expenditures in 2004. As in 2003, our most active drilling area in the Mid-Continent region in 2004 was in western Oklahoma in our Northeast Mayfield prospect area. Due to increased industry activity and expiring leases in the field, drilling in 2004 was more exploratory than in prior years as we stepped out to the south and to the west to test the limits of the play. Results were not as productive as they were in 2003 when we primarily drilled development locations. We completed 24 of the 28 wells drilled in the field in 2004. We are planning to drill 27 wells in 2005, which will include a higher percentage of development wells than we drilled in 2004. We will be drilling several exploratory wells in 2005 as we continue to evaluate our leases in the field. We have operated in the Mid-Continent region for over 30 years. Our land profes- sionals have many years of experience in the region negotiating lease agreements, working with other interest owners and solving lease issues. With 18 identified Morrow sands, five identified Atoka pay intervals and Granite Wash potential Drilling Expertise on the 68 sections where we have interests in the play, we will continue developing this field over a multi-year period. At the end of 2004, we have identified 60 proved undeveloped and probable locations and have additional reserves classified as possible in the field. We are planning to spend $36 million, or 41% of our Mid-Continent capital expenditures budget, to drill and complete wells in Northeast Mayfield in 2005. We have increased our presence in the Oklahoma portion of the Arkoma Basin where we have allocated $22 million or 25% of our 2005 Mid-Continent capital expenditures budget. We plan to drill 13 wells in the Centrahoma field where we are targeting the Cromwell, Wapanucka, Woodford and Oil Creek formations. We continue to evaluate our Arkoma acreage through geological mapping and 3-D seismic. In 2005 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 $87.0 million Mid-Continent 2005 capital expenditures budget is being allocated to prospects throughout the region. We are planning to drill six Granite Wash wells and ten Cottage Grove and Osborne wells in various fields in the Anadarko Basin. We will also be drilling ten horizontal coalbed methane wells in the Arkoma Basin on leases that are part of the January 2005 acquisition of Agate Petroleum, Inc. In 2005 we plan to operate three to five drilling rigs throughout the year in the Mid-Continent region and operate 80% of our capital expenditures budget. We have many years of experience directing drilling operations in the Mid-Continent. Being the low cost operator drilling 20,000 foot wells in Northeast Mayfield is a testament to our expertise. 9 Large Acreage Position A large lease inventory in Oklahoma provides exploration and development opportunities. Our leasehold position cannot easily be duplicated. Lease owners in Oklahoma are able to force a well to be drilled, even though the lease owner may own a minority lease position in the drill site (forced pooling). Geologic Expertise Our geologic managers have spent their entire careers in the Mid-Continent region. Their knowledge of the various plays, the performance of various formations and the opportunities that remain are vital to our continued growth of the region. 10 ARKLATE X REGION PROV ED RESERVES % OF TOTAL RESERVES GAS/OIL MIX PROV ED DEVELOP ED R ESE R VES TOTAL NET LEA SED ACR ES NET UNDEVELOPED LEA SED AC RE S NET MINERAL S ERV ITUD E ACR ES CAP ITA L EXPENDI TUR ES BUD GE T COMP ETIT IVE ADVANTAGE S ArkLaTex Region Horizontal Drilling Expertise 75 .6 BCF E 12% 89 % / 1 1% 83% 43 ,0 00 29% 9,5 14 $34 .6 MILL IO N 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 ArkLaTex region had excellent drilling results in 2004. The region drilled and participated in 32 wells, of which 29 were successful, for a 91% success rate. The region spent $28.8 million for exploration and development and $38.2 million for proved property acquisitions in 2004. The $67.0 million of capital expenditures represented 21% of our total capital expenditures in 2004. We had continued success in 2004 drilling horizontal wells in the James Lime formation. Our success in 2003 drilling in the Huxley field in east Texas was followed up in 2004 by drilling seven successful horizontal James Lime wells in our Spider, Bridges East and Huxley fields. In 2004 we also began drilling horizontal wells in the Pettet formation, which, like the James Lime formation, is a fractured limestone. We completed three Pettet wells in our Driscoll and Walker’s Chapel prospects in 2004. We are planning to drill 12 horizontal James Lime and Pettet wells in 2005, which represents 30% of the $34.6 million capital expenditures budget for the ArkLaTex region. The wells are expected to provide good economics as the average completed well cost is approximately $1.3 million, and per well reserves are estimated at 1.2 BCFE. In December 2004 we closed on a $38.2 million acquisition of oil and gas properties located primarily in the Elm Grove field in northern Louisiana. Included in the acquisition was a substantial inventory of drillable prospects in the Cotton Valley formation. We have included $8.4 million in our 2005 capital expenditures budget to participate in 42 Cotton Valley wells in the Elm Grove field this year. The balance of our $34.6 million ArkLaTex 2005 capital expenditures budget is being allocated to a mix of exploratory and development projects that include wells in our Box Church, Trinidad Southeast and Garrison fields in east Texas. We plan to operate 46% of our ArkLaTex capital expenditures budget in 2005. Our success drilling horizontal James Lime and Pettet wells over the past two years has created new horizontal well opportunities. Our expertise in geo-steering and well design of laterals has transformed formerly sub-economic reservoirs into low risk economic wells. Frac Technology We have been able to enhance production using recent developments in frac technology. Water and hybrid fracs have enhanced vertical production in tight gas sands. Improving the economics of sub-economic reservoirs has added to our inventory of drillable prospects. Geologic Expertise Our geologic managers have spent their entire careers exploring in east Texas and northern Louisiana. Their knowledge of the various plays, the performance of various formations and the opportunities that remain are vital to our continued growth of the region. 11 C OMP ETITIVE ADVANTAGES Gulf Coast Region Direct Hydrocarbon Indicator (DHI) Expertise GULF COAST AND PERMIAN BASIN REGIONS 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. Under new leadership and an experienced technical team, our 18-person office in Houston has revitalized our Gulf Coast Region. The ability of our geophysical staff to identify DHI improves our prospect inventory and reduces our risk. DHI is a valuable tool used to evaluate opportunities in south Texas, south Louisiana and offshore. Fee Property Gulf Coast Region P RO V ED R ESE RVES % O F TO TA L RES ERVE S G AS /O I L MIX P RO V ED D EVE LOPED R ESERVE S TO TA L N ET L EASED ACR ES N ET U ND E VELO PED LEASE D ACRE S FE E A CR ES C AP ITA L E XPEN DITU RES BU DG ET 3 3.5 BCF E 5 % 93% / 7% 9 3% 4 2,000 1 4% 24,914 $ 40.8 MILLION 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 24,914 acres of fee lands since 1938. The fee lands represent a smaller portion of our company’s production each year but still yielded $5.5 million of oil and gas royalty revenue to St. Mary in 2004. The onshore Gulf Coast and Gulf of Mexico became a core area in 1999 with the acquisition of King Ranch Energy. The region is focused on development and exploitation opportunities. Exploration is directed toward low and moderate risk opportunities with a direct hydrocarbon indicator (DHI) or areas where we have niche expertise. We anticipate drilling several exploration wells using DHI in 2005 that are the result of participation in a nearly 900 square mile 3-D seismic survey along the Gulf Coast of Texas and Louisiana. Approximately 25% of our $40.8 million Gulf Coast budget has been allocated to these opportunities. We plan to participate in approximately three DHI exploration wells in the shelf of the Gulf Cumulative production from our 24,914 acres of fee lands on the shoreline of the Gulf of Mexico exceeds 200 million barrels of oil and 3.5 TCF of gas. A 3-D seismic survey was conducted over the entire property in 2003. Excellent Leadership of Mexico in 2005. In addition, we plan to participate for the first time in an intermediate deepwater well. Approximately 43% of our Gulf Coast budget has been allocated to these offshore opportunities. We continue to participate in the successful development of the Judge Digby field, located in Point Coupe Parish outside Baton Rouge, Louisiana. Although the field is nearing the end of new drilling, we participated in the M C Delambre #1 well in 2004 that had an initial production rate of 15 MMCFD from the C-1 pay interval and logged 140 feet of sand in B zones that are currently behind pipe. We plan to participate in the drilling of one well and the recompletion of several wells in Judge Digby in 2005. As producing zones deplete, the wells are recompleted to the next uphole pay interval. 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. As the result of a 3-D seismic survey conducted over our 24,914-acre fee property in 2003, we issued leases on 2,845 acres in 2004. The lease terms allowed us to retain a 25% mineral owner’s royalty and the right to participate for up to a 25% working interest in any well drilled on the lease. This election is on a spacing unit basis. We anticipate wells being drilled on the leased acres in 2005. 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. We have assembled a talented team of professionals that are well connected within the oil and gas industry. The manager of our Gulf Coast region has many years of experi- ence successfully managing exploration and operations of other Gulf Coast operators. 12 Permian Basin Region PROVE D RESERVES % OF TOTAL RESERVES GAS/OIL MIX PROVE D DEVELOPED RE SE RVE S TOTAL NET LEAS ED A CRE S NE T UNDEV ELOP ED L EASED ACRE S CAPI TAL EXPENDITUR ES BU D G E T COMP ETIT IVE ADVANTAGE S Permian Region Waterflood Expertise 48 .5 BCF E 7% 14 % / 8 6% 63% 15 ,0 00 56% $10 .0 MILL IO N 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. Our activity in 2004 was primarily directed toward continued development of our waterflood projects at Parkway and East Shugart in Lea and Eddy Counties, New Mexico. Production at the Parkway Delaware Unit waterflood, which we initiated in 1999 when production was 350 Bbls per day, was enhanced by two infill wells drilled in 2004. Production in 2004 averaged 1,700 Bbls per day, up 46% from 2003. Production at the East Shugart Delaware Unit waterflood, which is an analog to the Parkway Delaware Unit, increased 5% in 2004 as the formation continues to respond to water injection. The Permian Basin region’s $10.0 million 2005 capital expenditures budget is being allocated primarily to 11 infill locations at Parkway and eight injection wells at East Shugart. We have been able to design and implement two successful waterflood operations of the Delaware formation in the Permian Basin. This expertise will assist us in identifying additional waterflood opportunities. 13 In every region, we create value for our shareholders by answering the question: Why are assets worth more in our hands? 14 15 DIRECTORS OFFICERS INFORMATION ABOUT RESERVES Barbara M. Baumann (1),(3),(4) Denver, Colorado President Cross Creek Energy Corporation Larry W. Bickle (2),(4) 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 Company Thomas E. Congdon (1) Denver, Colorado Former Chairman St. Mary Land & Exploration Company William J. Gardiner (1),(3) Houston, Texas Chief Financial Officer King Ranch Inc. Mark A. Hellerstein (1) Denver, Colorado Chairman, President and Chief Executive Officer St. Mary Land & Exploration Company John M. Seidl (2),(3) Aspen, Colorado William D. Sullivan (2),(4) The Woodlands, Texas Former Executive Vice President Anadarko Petroleum Corporation (1) Executive Committee (2) Nominating and Corporate Governance Committee (3) Audit Committee (4) Compensation Committee 16 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 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 Paul M. Veatch Vice President – General Manager, ArkLaTex 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 The SEC permits oil and gas companies to disclose in their public filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. St. Mary uses in portions of this annual report which are not publicly filed with the SEC the terms “probable” and “possible” reserves, which SEC guidelines prohibit from being included in public filings with the SEC. Probable reserves are unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. Possible reserves are unproved reserves which are less likely to be recoverable than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, our produc- tion forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. INFORMATION ABOUT FORWARD LOOKING STATEMENTS This annual report contains forward looking statements within the meaning of securities laws, including forecasts and projections for future periods. The words “will,” “believe,” “anticipate,” “intend,” “estimate,” “forecast,” “plan” and “expect” and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, which may cause St. Mary’s actual results to differ materially from results expressed or implied by the forward looking statements. These risks include such factors as discussed in the “Risk Factors” and “Cautionary Statement about Forward Looking Statements” sections of the accompanying 2004 Annual Report on Form 10-K. Although St. Mary may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by securities laws. SHAREHOLDER INFORMATION INV ES T OR 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 15, 2005 the Company had 28,798,362 shares of common stock outstanding. Market Prices 2004— Quarter Ended 2003— Quarter Ended March 31 June 30 September 30 December 31 high low high low $34.14 $27.74 $27.23 $23.80 37.19 40.13 43.00 31.80 31.76 37.12 29.75 28.85 29.19 24.65 24.45 24.45 OTHER INFORMATION In 2004, St. Mary submitted to the New York Stock Exchange a certificate of the Chief Executive Officer of St. Mary certifying that he was not aware of any violation by St. Mary of the New York Stock Exchange corporate governance listing standards. St. Mary has filed with the SEC certifications of each of the Chief Executive Officer and the Vice President-Finance required under Section 302 of the Sarbanes-Oxley Act as exhibits to the Annual Report on Form 10-K for the year ended December 31, 2004. 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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