SM Energy Co 10-K 2007
Documents found in this filing:
Washington, D.C. 20549
x Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2006
o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31539
ST. MARY LAND & EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
1776 Lincoln Street, Suite 700, Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No x
The aggregate market value of 53,716,420 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on June 30, 2006, the last business day of the registrants most recently completed second fiscal quarter, of $40.25 per share as reported on the New York Stock Exchange was $2,162,085,905. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the Company to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
As of February 16, 2007, the registrant had 55,004,399 shares of common stock outstanding, net of 250,000 treasury shares held by the Company.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrants definitive proxy statement relating to its 2007 annual meeting of stockholders to be filed within 120 days after December 31, 2006.
This Amendment on Form 10-K/A to the Annual Report on Form 10-K for the fiscal year ended December 31, 2006, by St. Mary Land & Exploration Company (the Company) is being filed to correct certain disclosures appearing under Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations, on pages 48, 51 and 52, and a disclosure appearing under Item 8, Financial Statements and Supplementary Data, in the Notes to Consolidated Financial Statements on page F-20.
Page 48 of the original filing incorrectly indicated that the number of shares of common stock issued by the Company in 2004 as a result of stock option exercises was 27,748 shares, whereas the correct amount was 1,399,052 shares. Page 51 of the original filing incorrectly indicated that the cash received from oil and gas sales, net of realized effects of hedging, increased $47.9 million to $758.9 million for the year ended December 31, 2006, whereas the correct amounts were $152.5 million and $802.1 million, respectively. Page 51 of the original filing also incorrectly indicated that the cash received from oil and gas sales, net of realized effects of hedging, increased $268.6 million to $651.6 million for the year ended December 31, 2005, whereas the correct amounts were $265.0 million and $649.6 million, respectively. Page 51 of the original filing further incorrectly indicated that the year ended December 31, 2004, reflected $20.7 million net cash received from short-term investments and from the expiration of the restriction period for funds held for tax-deferred exchange of oil and gas properties, whereas the correct amount was $21.4 million. Page 52 of the original filing incorrectly indicated that the 2006 increase in costs incurred for capital and exploration activities was a result of planned increases in drilling activity and a $196.2 million increase in acquisitions, whereas the correct amount was $195.0 million. Page F-20 of the original filing incorrectly indicated that the Companys interest rate for ABR loans when its borrowing base utilization percentage is greater than or equal to 50% but less than 75% is equal to prime plus 0.250%, whereas the correct interest rate is prime plus 0.000%.
Pursuant to the rules of the SEC, Item 15 of the original filing has been amended to contain currently dated certifications of the Companys Chief Executive Officer and Chief Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.
The correct amounts as described above are reflected in the corrected disclosures in this Form 10-K/A. All other information contained in the original Form 10-K remains unchanged, and the entire report with all Items is included in this Form 10-K/A for the convenience of the reader. The Company has not updated the disclosures contained herein to reflect events that occurred after the date of the original filing.
TABLE OF CONTENTS
TABLE OF CONTENTS
When we use the terms St. Mary, the Company, we, us, or our, we are referring to St. Mary Land & Exploration Company and its subsidiaries, unless the context otherwise requires. We have included technical terms important to an understanding of our business under Glossary. Throughout this document we make statements that are classified as forward-looking. Please refer to the Cautionary Information about Forward-Looking Statements section of this document for an explanation of these types of statements.
We are an independent oil and gas company engaged in the exploration, exploitation, development, acquisition and production of natural gas and crude oil. We were founded in 1908 and incorporated in Delaware in 1915. Our principal offices are located at 1776 Lincoln Street, Suite 700, Denver, Colorado 80203, and our telephone number is (303) 861-8140.
Our objective is to build stockholder value through consistent economic growth in reserves and production that increases net asset value per share. We seek to invest in oil and gas producing assets that result in a superior return on equity while preserving underlying capital, resulting in a return on equity to stockholders that reflects capital appreciation as well as the payment of cash dividends.
Our operations are focused in the following five core operating areas in the United States:
· The Rocky Mountain region is managed from our office in Billings, Montana. The oil and gas assets are located in the Williston Basin in eastern Montana and western North Dakota as well as the major producing basins in Wyoming. Recent activity in the northern Rockies includes drilling in the Middle Bakken formation, continued development in the Red River formation, and drilling horizontal prospects in the Mississippian formations of the Williston Basin, principally the Mission Canyon and Ratcliffe. As a follow-on to acquisitions made in the last several years, the Company has increased its activity in Wyoming, including development of legacy oil fields in the Big Horn and Wind River basins and gas development in the Greater Green River Basin. Our Rocky Mountain region also includes the development of coalbed methane reserves in the Hanging Woman Basin which is located in the northern Powder River Basin;
· The Mid-Continent region is comprised of properties in Oklahoma and northern Texas, primarily in the Anadarko and Arkoma basins. The most significant activity is in the Mayfield development area in Roger Mills and Beckham Counties in western Oklahoma and the horizontal Arkoma program in eastern Oklahoma, where we are pursuing a horizontal drilling program targeting the Wapanucka limestone, Cromwell sandstone, and Woodford shale formations. The Mid-Continent region is managed from our office in Tulsa, Oklahoma. Due to the specific technical expertise of the Mid-Continent team, the Companys assets in Constitution Field in Jefferson County, Texas are also managed within this region;
· The ArkLaTex region spans northern Louisiana, southern Arkansas, Mississippi, and eastern Texas and is managed by our Shreveport, Louisiana office. Recent activity includes the horizontal limestone program targeting resources in the James and Glen Rose formations throughout the region. The ArkLaTex region also manages our interests in a significant vertical well development effort at the Elm Grove Field. Elm Grove continues to be a strong producing asset with recent incremental success in the field from Hosston formation recompletions. This region also oversees our interest in the Terryville Field where we plan to increase activity in 2007;
· The Permian Basin region in western Texas and eastern New Mexico includes our recently acquired interests in the Sweetie Peck Field in the Midland Basin. Our activities in this field target the producing formations of the Spraberry intervalincluding the Spraberry, Leonard, and Wolfcamp formations. Our legacy assets in the Permian include our waterflood projects at Parkway Delaware Unit and East Shugart Delaware Unit in New Mexico. We opened an office in Midland, Texas in February 2007 to manage our Permian assets; and
· The Gulf Coast region consists of onshore Texas and Louisiana properties and includes the Judge Digby Field in Pointe Coupee Parish, Louisiana, our fee property in St. Mary Parish, Louisiana, and a presence in the offshore Gulf of Mexico. The region is managed from our Houston, Texas office. This office has expertise in the utilization of 3-D seismic to identify direct hydrocarbon indicators (DHI) along the Gulf Coast and in the Gulf of Mexico.
As of December 31, 2006, we had estimated proved reserves of 74.2 MMBbl of oil and 482.5 Bcf of natural gas, for a total of 927.6 BCFE. This represents an increase in reserve volumes of 17 percent from the end of 2005. The increase in reserves results from our drilling program whereby we added 115.8 BCFE and from acquisitions that added 99.2 BCFE. We had net upward revisions of 14.1 BCFE, which was comprised of an upward performance revision of 66.3 BCFE and a downward price revision of 52.2 BCFE. These proved oil and gas reserves have a PV-10 value of $2.2 billion and a standardized measure value, including the effect of income taxes of $1.6 billion. The percentage of proved developed reserves is 78 percent. The mix of natural gas reserves to oil reserves is 52 percent natural gas and 48 percent oil. Prices used to estimate oil and gas reserves were essentially flat for oil from a year earlier and down 44 percent year over year for natural gas, resulting in a decrease in PV-10 of 13 percent compared to last year. For the year ended December 31, 2006, we produced 92.8 BCFE, of which 61 percent was natural gas. This total production represents an average daily production of 254.2 MMCFE, a six percent increase from 2005.
Our reserve replacement percentage for 2006, including the effect of 3.1 BCFE of asset sales, was 244 percent of production. The reserve replacement percentage was 247 percent when the effect of divestitures is excluded. We acquired 99.2 BCFE through acquisitions in 2006, the majority of which came through our Sweetie Peck acquisition that closed in December 2006. Excluding acquisitions and divestitures, our reserve replacement percentage was 140 percent. The percentage of proved undeveloped reserves increased from 18 percent at the end of 2005 to 22 percent at December 31, 2006. This increase is directly related to the acquisition of proved undeveloped reserves associated with our Sweetie Peck acquisition, as well as recognition of increased per well proved undeveloped reserves in the ArkLaTex region due to continued success at Elm Grove. The increases were partially offset by the loss of proved undeveloped reserves in the Mid-Continent region attributable to the downward pricing revision referenced earlier. We believe the use of the term reserve replacement percentage is widely understood and utilized by those who make investment decisions related to the oil and gas exploration and production industry. Therefore, we believe this measure provides a useful basis of comparison to other companies and provides a measure of the growth of the Company.
In executing our business plan, we attempt to focus our resources in selected domestic basins where we believe our expertise in geology, geophysics, and drilling and completion techniques provide us with competitive advantages. In 2006, we spent $493.8 million in capital expenditures related to drilling activities, up 55 percent from the $319.3 million spent in 2005. This increase was due to a combination of increased activity throughout the Company and cost escalations throughout the year for drilling and field services. Additionally, we spent $28.8 million on leasehold interests during 2006, which is double that of the prior year. Our acquisition spending in 2006 was $282.9 million, which was a significant increase from the $87.8 million spent in 2005. The primary driver of the increase in acquisition spending was the $247.6 million Sweetie Peck acquisition in the Permian Basin which closed in December 2006.
Our total capital budget for 2007 is $821 million, which includes $721 million of exploration and development activities and $100 million for acquisitions. We continue to believe that acquisitions play a key role in our future growth and we will evaluate properties for acquisition that are in our core areas of operations or in new basins where we believe we have operating expertise and can effectively execute operations. In the past few years we have placed a greater emphasis on growth through the drill bit and growing our inventory of drilling prospects. This shift has been partially an evolution of strategy and partially a reflection of the very competitive nature of the acquisition market in recent years. Our ability to make a significant acquisition in 2006 was a result of having strong relationships within the industry, a detailed understanding of the underlying geology, operations, and leasehold situation related to the acquisition, and the ability to transact the acquisition in a negotiated manner rather than through a broad auction process.
The increase in budgeted exploration and development spending for 2007 represents a roughly $200 million or 41 percent increase over 2006. In our budgetary decisions, we measure and rank our projects based on their risk-adjusted estimated internal rate of return and return on investment. Balanced against this is the reality of lease term expirations, lease commitments, rig availability, permitting considerations and other operating aspects of managing an oil and gas company. Unlike the previous year, this years budget includes minimal cost escalations for drilling and field services. We believe we have begun to see a flattening of drilling and field service costs in our regions. The increase in our 2007 exploration and development budget is driven primarily by three factors. The first is an increase in Permian Basin spending that results from our planned execution of the drilling program associated with our Sweetie Peck acquisition. The second is an escalation of activity in our ArkLaTex region related to increased drilling and recompletion work in the Elm Grove Field together with an expansion of our horizontal limestone program in the James Lime formation. The third is an acceleration of the drilling program at our coalbed methane project at Hanging Woman Basin. Our base drilling program is a balanced program of low-to-medium-risk development and exploitation projects that provide a foundation for steady growth. We believe that the development of multi-year drilling programs in the Atoka/Granite Wash formations at Northeast Mayfield, the horizontal Arkoma Basin program targeting formations in the Wapanucka limestone, Cromwell sandstone, and Woodford shale, the Cotton Valley and Hosston plays at Elm Grove Field, our coalbed methane project in the Hanging Woman Basin, and the producing horizons of the Spraberry interval at the Sweetie Peck Field in the Permian Basin all help provide us with a core inventory of prospects for future development. We continue to work on developing or acquiring additional multi-year drilling programs in each of our regions.
As of December 31, 2006, we operated 67 percent of our properties on a reserve volume basis and 69 percent on a PV-10 value basis. We plan to operate 72 percent of our exploration and development budget in 2007. We believe it is important to operate a significant amount of our asset base as it allows us to control geologic and operational decisions as well as the timing of those decisions. We began 2007 with 12 operated drilling rigs running and plan to increase the operated rig count to 18 rigs by year-end.
Our 2007 acquisition budget is lower on a percentage basis than in prior years, although we will continue to seek acquisitions of oil and gas properties that complement our existing operations, offer economies of scale and provide further development, exploitation, and exploration opportunities. We will focus on areas where we have specialized knowledge or operating expertise that enable us to acquire attractively priced properties. In 2006, we acquired $282.9 million of oil and gas properties, most of which were purchased with cash from operations or with proceeds from our revolving credit facility. In 2006, we also closed a tax-deferred exchange of non-core assets in the Uinta Basin in Utah for oil and gas properties in Richland County, Montana. In addition to asset transactions, we have and will pursue corporate acquisitions that we believe are accretive to net asset value per share and that we are capable of integrating. In 2005, we acquired the stock of Agate Petroleum, Inc. for cash. Other examples of corporate acquisitions include the acquisition of Goldmark Engineering in 2004 for cash and the acquisitions of
Nance Petroleum Corporation and King Ranch Energy, Inc. in 1999, both of which were accomplished with the issuance of our common stock. The Flying J Oil & Gas Inc. property acquisition transaction completed in 2003 was not a corporate acquisition, yet we used a combination of restricted stock, a loan to Flying J, and options on our common stock for this transaction. When we consider the issuance of common stock for the acquisition of properties or a corporate entity, we base our investment decision primarily on the impact to net asset value per share.
We divest selected non-core assets when market conditions and prices are attractive. We will continue to evaluate such opportunities in the future when we believe it to be appropriate. During 2006, we sold properties with estimated proved reserves of 3.1 BCFE, or less than four-tenths of one percent of our reserves as of the beginning of the year.
In growing the Company, we seek to develop our existing property base and acquire acreage with additional potential in our core areas. From January 1, 2004 through December 31, 2006, we participated in the drilling of 1,493 gross wells with a success rate of 92 percent. During this three-year period we added estimated proved reserves of 596.3 BCFE at an average finding cost of $2.61 per MCFE. Not including the effect of divestitures, these results represent a three-year average reserve replacement percentage of 233 percent. Production has grown from an average daily rate of 206.0 MMCFE per day in 2004 to 254.2 MMCFE per day in 2006.
As of December 31, 2006, we had an acreage position of 2,244,488 gross (1,169,982 net) acres of which 1,272,789 gross (743,120 net) acres were undeveloped. Our percentage of undeveloped acreage on a gross and net basis is 57 percent and 64 percent, respectively. Our current leasehold position represents a seven percent increase on a gross acre basis and a six percent increase on a net acre basis from 2005. This growth in acreage is fundamental to our increasing emphasis on development of resource plays. In addition to our leased acreage position, we own 24,914 acres of fee properties in St. Mary Parish, Louisiana, of which 57 percent is undeveloped. Lastly, we have mineral servitudes representing 14,663 gross (9,868 net) acres in other portions of Louisiana, the majority of which is developed. We do not believe there are any substantial issues with respect to leasehold terms or expirations on our overall acreage holdings. We believe that our lease position provides a competitive advantage in certain locations and is a strategic asset for the Company.
Our senior technical managers in each region possess between 15 and 40 years of industry experience and lead fully-staffed regional technical offices that are supported by centralized administration from our corporate office in Denver. We use our comprehensive base of geological, geophysical, land, engineering, and production experience in each of our core operating areas to source prospects for our ongoing low-to-medium-risk development and exploitation programs. We conduct detailed geologic studies and use an array of technologies and tools including 2-D and 3-D seismic imaging, hydraulic fracturing and other reservoir stimulation techniques, horizontal drilling, secondary recovery, and specialized logging tools to enhance the potential of our existing properties.
Conservative use of financial leverage has long been a critical element of our strategy. We believe that maintaining a strong balance sheet is a significant competitive advantage that enables us to pursue acquisition and other opportunities, especially in weaker price environments. It also provides us with the financial resources to weather periods of volatile commodity prices or escalating costs. Our debt to book capitalization ratio was 37 percent at the end of December 2006. Included in our outstanding debt as of year-end is $100.0 million of Senior Convertible Notes which are callable in March 2007. We have called these Convertible Notes for redemption. The date of redemption will be March 20, 2007. As the conversion price of the Convertible Notes is $13.00 per share, we fully expect that the note holders will force conversion of the Convertible Notes into approximately 7.7 million shares of common stock. The contemplated conversion of these Convertible Notes to equity would give us a pro forma debt to book capitalization ratio of 29 percent at December 31, 2006.
In summary, we believe that our dedication to making investment decisions based on net asset value per share, our long-standing geologic and engineering experience in the regions in which we operate, our appropriate application of technology, our established networks of local industry relationships, and our acreage holdings in our core operating areas all provide us with competitive advantages that we can use to continue growing the Company.
· Senior Management Transition. During 2006, the Company underwent or announced personnel changes in the chief operating officer and chief executive officer roles. Doug York, our previous Chief Operating Officer, left the company in early 2006 to pursue other professional interests. Mark Hellerstein, our long-serving President and Chief Executive Officer, announced in mid-2006 his intention to retire from day-to-day management upon the successful transition of his duties to a successor. Tony Best, an executive with 28 years of experience in the oil and gas industry, joined the Company in June 2006 as President and Chief Operating Officer. Mr. Hellerstein and Mr. Best worked together through the second half of 2006 to develop a succession plan whereby Mr. Best would succeed Mr. Hellerstein as Chief Executive Officer in February 2007. Mr. Hellerstein will continue to serve as the Chairman of the Board. With Mr. Best taking over the role of CEO, the Company hired Jay Ottoson in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson has 22 years of operational and management experience in the oil and gas industry.
· 2006 Acquisition of Oil and Gas Properties. Our acquisitions of proved and unproved oil and gas properties in 2006 totaled $282.9 million. The most significant transaction was the purchase of oil and gas properties in the Sweetie Peck Field in the Permian Basin of west Texas for $247.6 million in December 2006. This acquisition represents the largest acquisition in our history and added 78.0 BCFE of proved oil and gas reserves. The acquisition led to the opening of a new office in Midland, Texas in February 2007 and the hiring of personnel charged with managing these assets. The Company also had several smaller niche transactions throughout the year in the Mid-Continent, ArkLaTex, and Rocky Mountain regions.
· Significant Volatility in Commodity Prices. During 2006, the exploration and production sector was impacted by volatility in the prices for crude oil and natural gas. Our operations and financial condition are significantly impacted by these prices. We sell the majority of our natural gas on contracts which use first of the month (also frequently referred to as bid week) index pricing. The Inside FERC contract price for January 2006 was $11.45 per MMBtu but declined to $4.20 per MMBtu by October 2006, spending much of the period in the $6 to $7 per MMBtu range during the year. The average NYMEX price for natural gas was $7.26 per MMBtu for 2006. Our crude oil is sold on contracts that pay us the average of posted prices for the period in which the crude oil is sold. NYMEX crude oil began 2006 with an average January price of $65.54 per barrel and reached a high average price for the year of $74.46 per barrel in July as tensions in the Middle East escalated. The average NYMEX price for the year was $66.22 per barrel. We hedge a portion of our oil and gas production using swaps and collars. A gain of $44.7 million was realized on our natural gas hedges for the year and a loss of $16.5 million was realized on our oil hedges for the year.
· Repurchase of Common Stock. The Company evaluates the market price of our common stock relative to our internal assessment of net asset value per share. To the extent that the market price per share is below what we believe to be the net asset value per share, we will repurchase shares under the program. In April and May of 2006, we repurchased 3.3 million shares of our common stock in the open market for a weighted-average price of $37.09, per share including commissions. These shares were purchased under a share repurchase program approved by the Board. At the time we repurchased our shares, we entered into hedges for a commensurate amount of our
production that was represented by the share repurchase in order to lock in the discounted price at which our shares were trading. In the third quarter, the Board authorized a refresh to the number of shares available for repurchase to a total of six million shares. This six million share authorization to repurchase common stock remains available as of the date of this filing.
· Increase in 2006 Year-End Reserves. Proved reserves increased 17 percent to 927.6 BCFE at December 31, 2006, from 794.5 BCFE at December 31, 2005. We added 115.8 BCFE from our drilling program and 99.2 BCFE from acquisitions. We had a 66.3 BCFE upward performance revision and a downward revision due to prices of 52.2 BCFE due to the decreased gas price at the end of 2006. We sold properties with reserves of 3.1 BCFE in 2006.
· Drilling Results. Reserve additions were driven principally from drilling results in the Rockies, Mid-Continent and ArkLaTex regions, with each region contributing approximately a quarter of the total reserve additions through drilling activities. The Gulf Coast realized reserve additions of 11.9 BCFE through the successful execution of its DHI program, which resulted in six successful wells out of eight attempts during 2006. The 34.5 BCFE increase in the Rockies can be attributed primarily to continued development of the Hanging Woman Basin coalbed methane project, as well as activities in the Bakken formation, various Mississippian formations, and the Red River formation. The Red River activity continues to provide reserve additions in the Rockies as we take advantage of 3-D seismic to identify structures. Our Mid-Continent reserve additions of 25.2 BCFE were primarily from continued development of the Northeast Mayfield area and the horizontal Arkoma program targeting the Wapanucka limestone, Cromwell Sandstone, and the Woodford shale. The ArkLaTex region grew from total proved reserves of 111.3 BCFE at the end of 2005 to 159.5 BCFE this yearend. This is the second year in a row where reserves in this region grew in excess of 40 percent from the prior year. This growth is a reflection of the value we are deriving from the Elm Grove Field development through both initial completions into the Lower Cotton Valley formation and subsequent recompletions using coiled tubing assisted fracturing in the Hosston. Additionally, we had a successful year in our horizontal limestone program in east Texas and western Louisiana.
· Hedging of Oil and Natural Gas through 2011. Beginning in October 2005, we entered into financial derivative transactions to hedge oil and gas prices on a significant portion of our proved developed producing assets. These hedges have been placed in the form of zero-cost collars. We have also hedged specific production related to acquisitions made in 2006 as well as the forecasted production for our 2007 Northeast Mayfield development program using swap contracts.
During 2006, no customer individually accounted for 10 percent of the Companys total oil and gas production revenue. During 2005, sales to Tesoro Refining and Marketing individually accounted for 13 percent of the Companys total oil and gas production revenue. During 2004 sales to Tesoro Refining and Marketing individually accounted for 20 percent of the Companys total oil and gas production revenue.
As of February 16, 2007, we had 359 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be good. We lease approximately 56,900 square feet of office space in Denver, Colorado for our executive and administrative offices, of which 9,500 square feet is subleased. We lease approximately 20,900 square feet of office space in Tulsa, Oklahoma; approximately 12,600 square feet in Shreveport, Louisiana; approximately 16,600 square feet in Houston, Texas; approximately 6,900 square feet in Midland, Texas; approximately 34,400 square feet in Billings, Montana; and approximately 2,000 square feet in Casper, Wyoming.
Substantially all of our working interests are held pursuant to leases from third parties. A title opinion is usually obtained prior to the commencement of drilling operations. We have obtained title opinions or have conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The majority of the value of our properties is subject to a mortgage under our credit facility, customary royalty interests, liens for current taxes, and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. We perform only a minimal title investigation before acquiring undeveloped leasehold.
Generally, but not always, the demand and price levels for natural gas increase during the colder winter months and decrease during the warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity is beginning to place an increasing demand on storage volumes. Crude oil and the demand for heating oil are also impacted by generally higher prices in the winter. Seasonal anomalies such as mild winters sometimes lessen these fluctuations. The impact of seasonality has somewhat been exacerbated by the overall supply and demand economics related to crude oil because there is a narrow margin of production capacity in excess of existing worldwide demand.
The oil and gas industry is intensely competitive. This is particularly true in the acquisition of prospective oil and natural gas properties and oil and gas reserves. We believe that our leasehold position provides a sound foundation for a robust drilling program. Our competitive position also depends on our geological, geophysical, and engineering expertise, and our financial resources. We believe that the location of our leasehold acreage, our exploration, drilling, and production expertise, and the experience and knowledge of our management and industry partners enable us to compete effectively in our core operating areas. Notwithstanding our talents and assets, we still face stiff competition from a substantial number of major and independent oil and gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity. We also compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for the drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time. Currently, access to incremental drilling equipment in certain regions is difficult but is not, at this time, anticipated to have any material negative impact on our ability to deploy our drilling capital budget for 2007. We are seeing signs of loosening rig availability, although it is quite specific by region. Finally, we also compete for people. As drilling activities have accelerated, the need for talented people has grown at a time when the number of people available is constrained.
Our business is subject to various federal, state, and local laws and governmental regulations that may be changed from time to time in response to economic or political conditions. Matters subject to regulation include the issuance of drilling permits, discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, and environmental protection. From time to time, regulatory agencies have imposed price controls and
limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.
Energy Regulations. Our sales of natural gas are affected by the availability, terms, and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. While the rules and regulations of the Federal Energy Regulatory Commission (FERC) have in the past greatly affected the production and sale of natural gas, the direct impact on the upstream exploration and production segment of the energy industry has greatly diminished in favor of allowing market forces to set the price paid for natural gas production. FERC regulations continue to affect the midstream and transportation segments of the industry and thus can have an indirect impact of the sales price we receive for natural gas production. There is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. We do not believe that we will be more materially affected by any action taken by the FERC or Congress than other natural gas producers and marketers with whom we compete.
Certain operations we conduct involve federal minerals administered by the Minerals Management Service. The MMS issues leases covering such lands through competitive bidding. These leases contain relatively standardized terms and require compliance with federal laws and detailed MMS regulations. For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers, and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. Lessees must also comply with detailed MMS regulations governing, among other things:
· Engineering and construction specifications for offshore production facilities;
· safety procedures;
· flaring of production;
· plugging and abandonment of Outer Continental Shelf (OCS) wells;
· calculation of royalty payments and the valuation of production for this purpose; and
· removal of facilities.
To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial, and we may not be able to continue to obtain bonds or other surety in all cases. Under certain circumstances the MMS may require our operations on federal leases to be suspended or terminated.
Many of the states in which we conduct our oil and gas drilling and production activities regulate such activities by requiring, among other things, drilling permits and bonds and reports concerning operations. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing of waste material, plugging and abandonment of wells, restoration requirements, unitization, pooling of natural gas and oil properties, and establishment of maximum rates of production from natural gas and oil wells. States generally have the ability to prorate production to the market demand for oil and natural gas; however, this is not currently occurring.
Environmental Regulations. Our operations are subject to numerous existing federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations may require that permits be obtained before drilling commences, restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities, and limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands, and other protected areas, including areas containing endangered animal species. As a result, these laws and regulations may substantially increase the costs of exploring, developing, or producing oil and gas and may prevent or delay the commencement or continuation of a project. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of such laws and regulations.
Our coalbed methane gas production from the Hanging Woman Basin is similar to our traditional natural gas production as to the physical producing facilities and the product produced. However, the subsurface mechanisms that allow the gas to move to the wellbore and the producing characteristics of coalbed methane wells are very different from traditional natural gas production. Unlike conventional gas wells, which require a porous and permeable reservoir, hydrocarbon migration, and a natural structural and/or stratigraphic trap, coalbed methane gas is trapped in the molecular structure of the coal itself until released by pressure changes resulting from the removal of in situ water. Frequently, coalbeds are partly or completely saturated with water. As the water is removed, internal pressures on the coal are decreased, allowing the gas to desorb from the coal and flow to the wellbore. Unlike traditional gas wells, new coalbed methane wells often produce water for several months and then, as the water production decreases, natural gas production increases.
Coalbed methane gas production in the Hanging Woman Basin requires state permits for the use of well-site pits and evaporation ponds for the disposal of produced water. Groundwater produced from the coal seams can generally be discharged into arroyos, surface waters, well-site pits, and evaporation ponds without a permit if it does not exceed surface discharge permit levels, and meets state and federal primary drinking water standards. All of these disposal options require an extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit standards. Where water of lesser quality is involved or the wells produce water in excess of the applicable volumetric permit limits, additional disposal wells may have to be drilled to re-inject the produced water back into deep underground rock formations.
A portion of our acreage at Hanging Woman Basin is on federal lands, and a segment of these federal lands are in Montana. We are subject to delays in permitting associated with the completion of a supplemental Environmental Impact Statement covering the contemplation of phased development on Federal leases in Montana. We are also affected by considerations for sage grouse that are native to the area. Each of these issues has the potential to impact the timing of our permitting and drilling operations associated with development of our reserves at Hanging Woman Basin.
To date we have not experienced any material adverse effect on our operations from obligations under environmental laws and regulations. We believe that we are in substantial compliance with currently applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us.
This Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe, or anticipate will or may occur in the future are forward-looking statements. The words anticipate, assume, believe, budget, estimate, expect, forecast, intend, plan, project, will, and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear in a number of places in this Form 10-K, and include statements about such matters as:
· The amount and nature of future capital expenditures and the availability of capital resources to fund capital expenditures;
· the drilling of wells and other exploration and development plans, as well as possible future acquisitions;
· reserve estimates and the estimates of both future net revenues and the present value of future net revenues that are included in their calculation;
· future oil and gas production estimates;
· our outlook on future oil and gas prices;
· cash flows, anticipated liquidity, and the future repayment of debt;
· business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations and our outlook on future financial condition or results of operations; and
· other similar matters such as those discussed in the Managements Discussion and Analysis of Financial Condition and Results of Operations section of this Form 10-K.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties which may cause our actual results to differ materially from results expressed or implied by the forward-looking statements. These risks are described in the Risk Factors section of this Form 10-K, and include such factors as:
· The volatility and level of realized oil and natural gas prices;
· unexpected drilling conditions and results;
· unsuccessful exploration and development drilling;
· the availability and risks of economically attractive exploration, development, and property acquisition opportunities and any necessary financing;
· the risks of hedging strategies;
· lower prices realized on oil and gas sales resulting from our commodity price risk management activities;
· the uncertain nature of the expected benefits from the acquisition of oil and gas properties;
· production rates and reserve replacement;
· the imprecise nature of oil and gas reserve estimates;
· uncertainties inherent in projecting future rates of production from drilling activities and acquisitions;
· drilling and operating service availability;
· uncertainties in cash flow;
· the financial strength of hedge contract counterparties;
· the negative impact that lower oil and natural gas prices could have on our ability to borrow;
· our ability to compete effectively against other independent and major oil and gas companies; and
· litigation, environmental matters, the potential impact of government regulations, and the use of management estimates.
We caution you that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those expressed or implied in the forward-looking statements. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by securities laws.
Our Internet website address is www.stmaryland.com. Within our websites financial information section we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC.
We also make available through our websites corporate governance section our Corporate Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for our Board of Directors Audit Committee, Compensation Committee, Executive Committee, and Nominating and Corporate Governance Committee. These documents are also available in print to any stockholder who requests them. Requests for these documents may be submitted to:
St. Mary Land & Exploration Company
Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this document.
The terms defined in this section are used throughout this Form 10-K.
2-D seismic or 2-D data. Seismic data that is acquired and processed to yield a two-dimensional cross-section of the subsurface.
3-D seismic or 3-D data. Seismic data that is acquired and processed to yield a three-dimensional picture of the subsurface.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet, used in reference to natural gas.
BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient commercial quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir beyond its known horizon.
Farmout. An assignment of an interest in a drilling location and related acreage conditioned upon the drilling of a well on that location.
Fee land. The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
Finding cost. Expressed in dollars per BOE or MCFE. Finding costs are calculated by dividing the amount of total capital expenditures for oil and gas activities, including the effect of asset retirement obligations, by the amount of estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates during the same period. The information for this calculation is included in the note regarding disclosures about oil and gas producing activities contained in the Notes to Consolidated Financial Statements included in this Form 10-K.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Horizontal wells. Wells which are drilled at angles greater than 70 degrees from vertical.
Hydraulic fracturing. A procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability and porosity.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBOE. One million barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
Mcf. One thousand cubic feet, used in reference to natural gas.
MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMcf. One million cubic feet, used in reference to natural gas.
MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.
MMBtu. One million British Thermal Units. A British Thermal Unit is the amount of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Net acres or net wells. The sum of our fractional working interests owned in gross acres or gross wells.
Net asset value per share. The result of the fair market value of total assets less total liabilities, divided by the total number of outstanding shares of common stock.
NYMEX. New York Mercantile Exchange.
OCS. Outer Continental Shelf in the Gulf of Mexico.
PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period.
Productive well. A well that is producing oil or gas or that is capable of commercial production.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, gas and gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The completion in an existing wellbore in a formation other than that in which the well has previously been completed.
Reserve life. Expressed in years, represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.
Reserve replacement percentageexcluding sales. The sum of reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period of time. This is believed to be a useful non-GAAP measure that is widely utilized within the exploration and production industry as well as by investors. It is an easily calculable number and is representative of the relative success a company is having in replacing its production from its declining asset base as well as its ability to grow the overall company.
Reserve replacement percentageincluding sales. The sum of sales of reserves, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous estimates for a specified period of time divided by production for that same period of time. This is believed to be a useful non-GAAP measure that is widely utilized within the exploration and production industry as well as by investors. It is an easily calculable number and is representative of the relative success a company is having in replacing its production from its declining asset base as well as its ability to grow the overall company.
Royalty. The share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and gas produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.
Royalty interest. An interest in an oil and gas property entitling the owner to shares of oil and gas production free of costs of exploration, development, and production operations.
Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on year-end prices, costs and statutory tax rates, and a 10 percent annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas
producing activities contained in the Notes to Consolidated Financial Statements included in this Form 10-K.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated net proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.
In addition to the other information included in this Form 10-K, the following risk factors should be carefully considered when evaluating St. Mary.
Oil and natural gas prices are volatile, and a decline in prices could hurt our profitability, financial condition, and ability to grow.
Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and gas properties depend heavily on the prices we receive for oil and natural gas sales. Oil and gas prices also affect our cash flows and borrowing capacity, as well as the amount and value of our oil and gas reserves.
Historically, the markets for oil and gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and gas, market uncertainty, and other factors that are beyond our control, including:
· Worldwide and domestic supplies of oil and natural gas;
· the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain production quotas;
· pipeline, transportation, or refining capacity constraints in a regional or localized area may put downward pressure on the realized price for oil or natural gas;
· political instability or armed conflict in oil or gas producing regions;
· worldwide and domestic economic conditions;
· the level of consumer demand;
· productive capacity of the industry as a whole;
· the availability of transportation facilities;
· weather conditions;
· the price and availability of alternative fuels; and
· governmental regulations and taxes.
These factors and the volatility of oil and gas markets make it very difficult to predict future oil and gas price movements with any certainty. Declines in oil or gas prices would reduce our revenues and could also reduce the amount of oil and gas that we can produce economically, which could have a material adverse effect on us.
If we are not able to replace reserves, we will not be able to sustain production.
Our future operations depend on our ability to find, develop, and acquire oil and gas reserves that are economically recoverable. Our properties produce oil and gas at a declining rate over time. In order to maintain current production rates we must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We may do this even during periods of low oil and gas prices. In addition, competition for the acquisition of producing oil and gas properties is intense and many of our competitors have financial and other resources for acquisitions that are substantially greater than those available to us. Therefore, we may not be able to acquire oil and gas properties that contain economically recoverable reserves, or we may not be able to acquire such properties at prices acceptable to us. Without successful drilling or acquisition activities, our reserves, production, and revenues will decline over time.
Competition in our industry is intense, and many of our competitors have greater financial and technical resources than we do.
We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers, and institutional and individual investors who are actively seeking oil and gas properties throughout the world, along with the equipment, expertise, labor, and materials required to operate oil and gas properties. Many of our competitors have financial and technical resources vastly exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for the properties. In addition, shortages of equipment, labor, or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We may not be successful in acquiring and developing profitable properties in the face of this competition.
We also compete for people. As drilling activities have accelerated, the need for talented people has grown at a time when the number of people available is constrained.
The actual quantities and present values of our proved oil and gas reserves may be less than we have estimated.
This Form 10-K and other SEC filings by us contain estimates of our proved oil and gas reserves and the estimated future net revenues from those reserves. Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes, timing of operations, and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables and therefore changes often occur as these variables evolve and commodity prices fluctuate. Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, production taxes, development expenditures, operating expenses, and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present values of proved reserves disclosed by us, and the actual quantities and present values may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.
As of December 31, 2006, approximately 22 percent, or 200.1 BCFE, of our estimated proved reserves were proved undeveloped and approximately 11 percent or 100.1 BCFE, were proved developed non-producing. Estimates of proved undeveloped reserves and proved developed non-producing reserves are
nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. Our estimates of proved undeveloped reserves assume that we will make significant capital expenditures to develop these reserves, including an estimated $185 million in 2007. Although we have estimated our reserves and the costs associated with these reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated.
You should not assume that the PV-10 values included in this Form 10-K represent the current market value of our estimated oil and natural gas reserves. Management has based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, in accordance with SEC requirements, whereas actual future prices and costs may be materially higher or lower. For example, values of our reserves as of December 31, 2006, were estimated using a calculated weighted-average sales price of $5.64 per Mcf of gas (Gulf Coast spot price) and $61.05 per Bbl of oil (NYMEX). We ensure that we consider basis and location differentials as of that date in estimating our reserves. During 2006 our monthly average realized gas prices, excluding the effect of hedging, were as high as $8.65 per Mcf and as low as $4.97 per Mcf. For the same period our monthly average realized oil prices were as high as $69.58 per Bbl and as low as $50.61 per Bbl. Many other factors will affect actual future net cash flows, including:
· The amount and timing of actual production;
· supply and demand for oil and natural gas;
· curtailments or increases in consumption by oil purchasers and natural gas pipelines; and
· changes in governmental regulations or taxes.
The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10 values. In addition, the ten percent discount factor required by the SEC to be used to calculate PV-10 values for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business and the oil and natural gas industry in general are subject.
Our producing property acquisitions may not be worth what we paid due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration potential, future oil and gas prices, operating costs, and potential environmental and other liabilities. These assessments are not precise and their accuracy is inherently uncertain.
In connection with our acquisitions, we perform a customary review of the acquired properties that will not necessarily reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an as is basis with limited remedies for breaches of representations and warranties.
In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such acquisitions may be limited.
Integrating acquired properties and businesses involves a number of other special risks, including the risk that management may be distracted from normal business concerns by the need to integrate operations and systems as well as retain and assimilate additional employees. Therefore, we may not be able to realize all of the anticipated benefits of our acquisitions.
Exploration and development drilling may not result in commercially productive reserves.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas will be found. The cost of drilling and completing wells is often uncertain, and oil and gas drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
· Unexpected drilling conditions;
· title problems;
· pressure or geologic irregularities in formations;
· equipment failures or accidents;
· adverse weather conditions;
· compliance with environmental and other governmental requirements;
· shortages or delays in the availability of or increases in the cost of drilling rigs, fracture stimulation crews and equipment, chemicals and supplies, and
· shortages in availability of experienced drilling crews.
The prevailing prices of oil and gas also affect the cost of and the demand for drilling rigs, production equipment, and related services. The availability of drilling rigs can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.
Another significant risk inherent in our drilling plans is the need to obtain drilling permits from state, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays which jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to explore on or develop our properties.
The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies that we use do not allow us to know conclusively prior to drilling a well that oil or gas is present, or whether it can be produced economically. The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Drilling activities can result in dry wells or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling and completion costs.
Our future drilling activities may not be successful. Our overall drilling success rate or our drilling success rate for activity within a particular area may decline. In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.
Our hedging transactions may limit the prices that we receive for oil and gas sales and involve other risks.
To manage our exposure to price risks in the sale of our oil and natural gas, we enter into commodity price risk management arrangements from time to time with respect to a portion of our current or future production. We have hedged a significant portion of anticipated future production from our currently producing properties using zero-cost collars and swaps. Commodity price hedging may limit the prices that we receive for our oil and gas sales if oil or natural gas prices rise substantially over the price established by the hedge. In addition, these transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
· Our production is less than expected;
· there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or
· the counterparties to our hedge contracts fail to perform under the contracts.
Some of our hedging agreements may also require us to furnish cash collateral, letters of credit, or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by us to the counterparties, which would impact our liquidity and capital resources. In addition, some of our hedging transactions use derivative instruments that may involve basis risk. Basis risk in a hedging contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.
Future oil and gas price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.
We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write down the costs of each such field to our estimate of fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.
We review the carrying value of our properties quarterly based on prices in effect as of the end of each quarter or as of the time of reporting our results. Once incurred, a write-down of oil and gas properties cannot be reversed at a later date even if oil or gas prices increase.
Substantial capital is required to replace our reserves.
We need to make substantial capital expenditures to find, acquire, develop, and produce oil and natural gas reserves. Future cash flows and the availability of financing are subject to a number of factors,
such as the level of production from existing wells, our success in locating and acquiring new reserves, and prices paid for oil and natural gas. If oil or gas prices decrease or we encounter operating difficulties that result in our cash flows from operations being less than expected, we may have to reduce our capital expenditures unless we can raise additional funds through debt or equity financing. Debt or equity financing may not always be available to us in sufficient amounts or on acceptable terms.
If our revenues were to decrease due to lower oil or gas prices, decreased production, or other reasons, and if we could not obtain capital through our credit facility or other acceptable debt or equity financing arrangements, our ability to execute our development plans, replace our reserves, or maintain production levels could be greatly limited.
A decrease in oil or gas prices could limit our ability to borrow under our credit facility.
Our credit facility has a maximum loan amount of $500 million, subject to a borrowing base that the lenders periodically redetermine based on the value of our oil and gas properties, which in turn is based in part on oil and gas prices. Lower oil or gas prices in the future could limit our borrowing base and reduce our ability to borrow under the credit facility.
We could incur substantial additional debt, which could limit our financial flexibility.
As of December 31, 2006, we had $334.0 million in outstanding borrowings under our bank credit facility and $100.0 million in outstanding long-term debt under our 5.75 % Senior Convertible Notes due 2022. We also had a current note payable due to an individual that sold certain oil and gas properties to us in 2006. This note amount was $4.5 million at December 31, 2006, and was paid subsequent to year end. Our long-term debt represented 37 percent of our total book capitalization as of December 31, 2006. The contemplated conversion of these Convertible Notes to equity would give us a pro forma debt to book capitalization ratio of 29 percent at December 31, 2006. Our credit facility has a maximum loan amount of $500 million, a current borrowing base of $900 million, and we have elected a current commitment amount of $500 million.
Our level of debt could have important consequences for our operations, including:
· Requiring us to dedicate a substantial portion of our cash flows from operations to make required payments on debt, thereby reducing the availability of cash flows for working capital, capital expenditures, and other general business activities;
· limiting our ability to obtain additional financing in the future for working capital, capital expenditures, and other general business activities, or increasing the costs for such additional financing;
· limiting our flexibility in planning for, or reacting to, changes in our business and our industry; and
· increasing our vulnerability to adverse effects from a downturn in our business or the general economy.
We may incur additional debt, including secured debt under our credit facility or otherwise, in order to make future acquisitions or to develop our properties. An increased level of debt increases the risk that we may default on our debt obligations. We may not be able to generate sufficient cash flow from operations or be able to make other arrangements for the repayment or refinancing of the debt.
In addition, our credit facility is subject to periodic borrowing base redeterminations. We could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing or arrange new financing, we may be forced to sell significant assets.
We are subject to operating and environmental risks and hazards that could result in substantial losses.
Oil and gas operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, adverse weather such as hurricanes in the Gulf Coast region, freezing conditions, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas, and other environmental risks and hazards. If any of these types of events occurs, we could sustain substantial losses.
Under certain limited circumstances we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease, or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions or cause us to incur losses.
We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damages. We do not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages or insurance coverage for environmental damage that occurs over time is available at a reasonable cost. In addition, pollution and environmental risks generally are not fully insurable. Further, we may elect not to obtain other insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks presented. Accordingly, we may be subject to liability or may lose substantial portions of certain properties in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer a material loss.
Following the hurricanes in 2004 and 2005, the insurance markets have suffered significant losses. As a result, the availability of coverage and the cost at which such coverage will be available in the future is uncertain and as evidenced in 2006, was substantially more expensive than in prior years.
Our operations are subject to complex laws and regulations, including environmental regulations that result in substantial costs and other risks.
Federal, state, and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. Noncompliance with statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability.
Governmental authorities regulate various aspects of oil and gas drilling and production, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. To cover the various obligations of leaseholders in federal waters, federal authorities generally require that leaseholders have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or other assurances can be substantial, and we may not be able to obtain bonds or other assurances in all cases. Under limited circumstances, federal authorities may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could have a material adverse effect on our operations. Our development at Hanging Woman Basin is particularly affected, as a portion of our acreage is on federal lands.
Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent
interpretations between state and federal agencies. We could face significant liabilities to governmental authorities and third parties for discharges of oil, natural gas, or other pollutants into the air, soil, or water, and we could be required to spend substantial amounts on investigations, litigation, and remediation. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a materially adverse effect on us.
In addition, in response to studies suggesting that emissions of certain gases may be contributing to warming of the Earths atmosphere, many states are beginning to consider initiatives to track and record these gases, generally referred to as greenhouse gases, with several states having already adopted regulatory initiatives and one state, California, having adopted legislation aimed at reducing emissions of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are included among the types of gases targeted by greenhouse gas initiatives and laws. This movement is in its infancy but regulatory initiatives or legislation placing restrictions on emissions of methane or carbon dioxide that may be imposed at the federal, state and local level could adversely affect our operations and the demand for our products.
We depend on transportation facilities owned by others.
The marketability of our oil and gas production depends in part on the availability, proximity, and capacity of pipeline transportation systems owned by third parties. The lack of available transportation capacity on these systems and facilities could result in the shutting-in of producing wells, the delay or discontinuance of development plans for properties, or lower price realizations. Although we have some contractual control over the transportation of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could adversely affect our ability to produce, gather, and transport oil and natural gas.
The price of our common stock may fluctuate significantly, which may result in losses for investors.
From January 1, 2005, to February 16, 2007, the last daily sale price of our common stock as reported by the New York Stock Exchange ranged from a low of $19.45 per share to a high of $45.28 per share, as adjusted to reflect our 2-for-1 stock split effected in the form of a stock dividend on March 31, 2005. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:
· Changes in oil or natural gas prices;
· variations in quarterly drilling, recompletions, acquisitions, and operating results;
· changes in financial estimates by securities analysts;
· changes in market valuations of comparable companies;
· additions or departures of key personnel; and
· future sales of our common stock.
We may fail to meet expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.
Our certificate of incorporation and bylaws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment.
Our certificate of incorporation and bylaws contain provisions that may have the effect of delaying or preventing a change of control. These provisions, among other things, provide for non-cumulative voting in the election of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of Directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other and with the shareholder rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.
Under our shareholder rights plan, if the Board of Directors determines that the terms of a potential acquisition do not reflect the long-term value of St. Mary, the Board of Directors could allow the holder of each outstanding share of our common stock other than those held by the potential acquirer to purchase one additional share of our common stock with a market value of twice the exercise price. This prospective dilution to a potential acquirer would make the acquisition impracticable unless the terms were improved to the satisfaction of the Board of Directors. The existence of the plan may impede a takeover not supported by our Board even though such takeover may be desired by a majority of our stockholders or may involve a premium over the prevailing stock price.
Our shares that are eligible for future sale may have an adverse effect on the price of our common stock.
As of February 16, 2007, we had 55,004,399 shares of common stock outstanding, net of 250,000 shares held in treasury. Of the net shares outstanding, 54,909,904 shares were freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. Also as of that date, options to purchase 3,118,936 shares of our common stock were outstanding, of which 2,964,278 were exercisable. These options are exercisable at prices ranging from $4.62 to $20.87 per share. In addition, restricted stock units providing for the issuance of up to a total of 1,061,223 shares of our common stock were outstanding. Further, we expect to issue approximately 7,692,300 shares of common stock upon conversion of the $100 million of our Senior Convertible Notes. The number of shares is based on the conversion price of $13.00 per share. Conversion is expected as an outcome of our recent announcement to call the notes for redemption on March 20, 2007. Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of options and restricted stock units to issue shares of common stock at prices that may be below the then-current market price of the common stock could adversely affect the market price of the common stock and could impair our ability to raise capital through the sale of our equity securities.
We may not always pay dividends on our common stock.
The payment of future dividends remains in the discretion of the Board of Directors and will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to covenants in our credit facility, including a covenant regarding the level of our current ratio of current assets to current liabilities and a limit on the annual dividend rate that we may pay to no more than $0.25 per share. The Board of Directors may determine in the future to reduce the current semi-annual dividend rate of $0.05 per share or discontinue the payment of dividends altogether.
A director and his extended family may be able to exert influence over us.
Thomas E. Congdon, a director and our former Chairman of the Board, and members of his extended family are estimated to own between one and five percent of the outstanding shares of our common stock
as of February 16, 2007. While no formal arrangements exist, these extended family members could be inclined to act in concert with Mr. Congdon on matters related to control of St. Mary, including for example the election of directors or in response to an unsolicited proposal to acquire St. Mary. Accordingly, Mr. Congdon and his family may be able to influence matters presented to our Board of Directors and stockholders.
St. Mary has no unresolved comments from the SEC staff regarding its periodic or current reports under the Securities Exchange Act of 1934.
St. Marys exploration, development, and acquisition activities and oil and gas properties are focused in five core operating areas: the Rocky Mountain region; the Mid-Continent region; the ArkLaTex region; the Permian Basin region; and the Gulf Coast region. Our Hanging Woman Basin project is within our Rocky Mountain region and is managed by personnel from our Billings, Montana office. Information concerning each of our major areas of operations is shown below with the summary of our estimated proved reserves as of December 31, 2006.
Rocky Mountain Region. Nance Petroleum Corporation, a wholly-owned subsidiary of St. Mary, has conducted operations on behalf of the Company in the Williston Basin in eastern Montana and western North Dakota since 1991. Our office in Billings, Montana has a full-time staff of 112 people. We have expanded our operations into the Greater Green River, Powder River, Big Horn, and Wind River basins of Wyoming over the past several years as a result of acquisitions. The largest growth in the region came in late 2002 and early 2003 with significant property acquisitions from Choctaw, Burlington Resources, and Flying J. These transactions brought with them a tremendous acreage position that has precipitated additional growth in this region.
St. Mary spent $161.3 million in 2006 on exploration, development, and acquisitions in the Rocky Mountain region including Hanging Woman Basin, with $146.4 million directed towards drilling and leasing activities. In 2005, $197.0 million was spent in the Rockies, including $22.9 million at Hanging Woman Basin. The relative decrease in total capital from the prior year reflects the Agate and Wold acquisitions that occurred in 2005. In recent years, our conventional Rockies program has focused on the horizontal Bakken play, although the level of activity is decreasing in 2007. We continue to develop the Red River formation using smaller 3-D seismic surveys. We have successfully used 3-D seismic imaging to delineate structure and porosity development in this formation. As a result of transactions in 2004 and 2005, including Goldmark, Agate, and Wold, we have acquired a position in a number of legacy oil fields in
the Big Horn and Wind River basins, as well as a presence in the Greater Green River Basin. Production in 2006 from conventional oil and gas in the Rockies was 37.5 BCFE, 79 percent of which was oil. This represents an increase of one percent from production of 37.2 BCFE for 2005. Proved reserves for conventional Rockies assets in 2006 were 389.6 BCFE, 92 percent of which were proved developed and 81 percent of which were oil. This represents a decline of three percent from 2005 year-end proved reserves. Reserves declined in 2006 as our production was not replaced by our drilling or acquisition activity. Our drilling, while successful overall, resulted in more marginally productive wells in the Bakken formation during 2006 as we near the end of that specific drilling program. Additionally, reserves and production were negatively impacted by our inability to secure a drilling rig in the southern Rockies for most of the year.
The Elm Coulee Field in the Rockies is the highest value field in the region at year-end 2006, with proved reserves of 43.8 BCFE and a PV-10 value of $143.0 million. The reserves in this field are predominately oil and the Bakken is the formation of primary interest. This field comprises approximately seven percent of the entire Companys PV-10 value of $2.2 billion and is represented by interest in 89 gross wells with an average working interest of 54 percent.
Another significant drilling program in the Rockies is at our Hanging Woman Basin coalbed methane development in the northern Powder River Basin. In 2006, we spent a total of $30.4 million developing this program. We participated in 138 wells, 132 of which were operated, as well as the build out of the necessary infrastructure to operate in the area. Production from Hanging Woman Basin began in mid-December 2004, was 0.5 Bcf in 2005, and quadrupled to 2.0 Bcf in 2006. Due to regulatory and permitting delays, significant dewatering time, and low production rates per well, it will take a number of years to develop the field to the point of having production volumes that are meaningful to our total production profile. Even so, we expect to see significant percentage increases in annual production for several years. Proved reserves at December 31, 2006, were 33.4 Bcf, 91 percent of which were proved developed. This represents a 32 percent increase in proved reserves year-over-year. All of these reserves are located on our acreage in Wyoming.
Our capital budget for the Rocky Mountain region represents the largest portion of our 2007 drilling budget at approximately $213 million for 2007, with $155 million budgeted for the conventional Rockies program and $58 million budgeted for activities at Hanging Woman Basin. In the conventional Rockies program, we plan to drill or participate in 178 gross wells in 2007. We will operate 81 percent of the planned capital expenditures forecasted for the conventional Rockies. Our operated activities are focused on expanding a horizontal re-entry program targeting the Madison and Mission Canyon formations, drilling and re-entering wells in the legacy Murphy Dome oil field, and targeting the Lewis and Almond formations in the Greater Green River Basin. Fewer operated wells are planned for the Bakken program in 2007 as this successful grass roots program is nearing the end of primary development. However, we do plan to attempt a handful of horizontal re-entry wells targeting this formation. We will continue to exploit what we believe to be a competitive advantage in the Red River formation in 2007. The plans of our non-operated partners in 2007 are dominated by horizontal Bakken, Madison, and Mission Canyon wells, as well as a significant number of wells at the Atlantic Rim coalbed methane development in Wyoming. At Hanging Woman Basin, our plan is to drill or participate in 258 wells in 2007. All of the activity in the Hanging Woman Basin this year is scheduled to occur in Wyoming. We will operate 84 percent of the gross well activity and 87 percent of the planned capital expenditures. Our operated drilling program anticipates growing to a four rig program during the year. The majority of our operated activity will focus on the shallow and intermediate coal benches. Additional horizontal wells are planned for the deep coal package during 2007, and we will continue to monitor the results of the four deep horizontal wells that were drilled in late 2006. We do not expect to have enough information to make an assessment of the horizontal program until late 2007 or early 2008.
Mid-Continent Region. St. Mary has been active in the Mid-Continent region since 1973. Operations for the region are managed by our 50 full-time employees in Tulsa, Oklahoma. We have been active in the Anadarko Basin of western Oklahoma since our entry into the region and have begun operating in the Arkoma Basin in eastern Oklahoma in recent years. Our long history of operations and proprietary geologic knowledge enables us to sustain economic development and exploration programs despite periods of adverse industry conditions. We apply current technology through the use of hydraulic fracturing, innovative well completion techniques, and horizontal drilling to accelerate production and associated cash flow from the regions tight gas reservoirs and developing plays.
In 2006, we spent $214.3 million in the Mid-Continent region on exploration, development, and acquisition activity, which is 58 percent more than the $135.6 million spent in 2005. The increase in 2006 is the result of drilling and service cost inflation and additional activity in our horizontal Arkoma program targeting the Wapanucka limestone, Cromwell sandstone, and Woodford shale formations, as well as a moderate ramp up of activity in the Constitution field and throughout the Anadarko Basin. We were also much more active in the leasing aspect of our business in 2006, spending $17.7 million, which is almost four times the amount spent on leasing in 2005. Mid-Continent production in 2006 was 29.8 BCFE, 92 percent of which was natural gas. This is an increase of 13 percent from the 26.5 BCFE produced in 2005. Proved reserves at the end of 2006 were 170.7 BCFE, 94 percent of which were proved developed and 95 percent of which were natural gas. Year over year, proved reserves dropped three percent from 175.4 BCFE at December 31, 2005. The Mid-Continent decrease was primarily caused by a downward price revision of 28.9 BCFE in 2006, as natural gas prices used to calculate SEC proved reserves declined 44 percent year-over-year to $5.64 per MMBtu. While we are subject to the volatility of commodity prices with respect to the calculation of year-end SEC proved reserves, we believe our active hedging program protects our economics despite periodic swings in commodity prices that can result in negative reserve revisions due to price reductions. Although we may be helped by the financial protection offered by our derivative contracts, our individual well economics must also meet acceptable return criteria in order to proceed with drilling activity.
The Paggi Broussard #1 well operated by our Mid-Continent region is the highest single value property in the Company, with 8.5 BCFE of proved reserves and a PV-10 value of $47.4 million as of December 31, 2006. This single well represents two percent of our entire PV-10 value of $2.2 billion. The well was drilled in late 2004 and has shown remarkably little decline in the time since it was placed online. The Paggi Broussard #2 was drilled and placed online in mid-2006 and is the second highest value well and fifth largest value entity in the Company with proved reserves of 3.2 BCFE and a PV-10 value of $17.2 million as of December 31, 2006. The largest value field in the Mid-Continent is Northeast Mayfield which produces primarily from the Morrow and Atoka/Granite Wash formations. At the end of 2006 the proved reserves at Northeast Mayfield were 37.3 BCFE and the PV-10 value was $88.1 million.
The 2007 capital expenditure budget for the Mid-Continent region is $206 million, 82 percent of which will be operated by the Company. The largest component of the budget is our program in the Arkoma basin, where 17 operated wells are planned. The majority of these will be horizontal wells targeting the Woodford shale formation. Activity in the horizontal Arkoma program is currently focused on the Woodford shale as it is the deepest of the three zones of interest, and by drilling to the Woodford we will hold the acreage through that depth. We continue to evaluate our drilling and completion efforts in the horizontal Arkoma program to ensure we are improving and maximizing the potential of this program. The next most significant program is the Atoka/Granite Wash program in the Mayfield development area where we will drill or participate in 30 gross wells in 2007, 18 of which will be operated by the Company. The production profile of Atoka/Granite Wash wells is such that approximately 50 percent of the expected total production is recovered within the first year, and therefore these wells can be more economically sensitive to commodity price volatility. As a result, we have hedged the anticipated production from the planned 2007 Atoka/Granite Wash program for the next two years to ensure that our economic thresholds
are being met. We evaluate the commodity price and cost environment prior to drilling each well to ensure the well project meets our economic standards. However, our hedging program provides us the flexibility to continue drilling should operational or leasehold issues dictate moving forward with the program when the current economics for individual wells may be currently unfavorable. The Company has also budgeted capital for wells targeting the Springer and Britt formations in 2007.
ArkLaTex Region. Our 24 full-time employees in Shreveport, Louisiana manage St. Marys operations in the ArkLaTex region. The ArkLaTex region was the first operating office for the Company, originating from the acquisition of oil and gas assets from T.L. James & Company in 1992. For years the activities of this region focused on the tight sandstone Cotton Valley and Travis Peak formations in the region. In recent years, we have added development of limestone carbonates in the ArkLaTex, including the James, Glen Rose, Rodessa, and Pettit formations.
The ArkLaTex region spent $88.0 million in 2006 on exploration, development, and acquisition activities, which is double the $44.0 million spent in 2005. The primary drivers of this increase in capital were an increase in activity at Elm Grove and an escalation of cost in our horizontal limestone program related to a new completion technique. Our non-operated interests in the Elm Grove Field were purchased in late 2004, and since that time the ownership in the field has consolidated considerably. This consolidation has allowed the remaining owners to accelerate development of the Lower Cotton Valley formation which has historically been the target interval in this field. The increase in activity has occurred in areas of the field where we have relatively higher working interests, thereby increasing our capital expenditures in the field. In the horizontal limestone program, we began using a new completion technique in 2006 that allows us to isolate sections of the horizontal wellbore. By isolating different sections we can complete and stimulate each isolated section in a manner that is optimal for that particular segment of the formation. While this technique increased our costs significantly, it also increased our production and reserves per well, thereby economically justifying the additional expenditure. The regions 2006 production was down two percent to 10.5 BCFE. The production in the region is 92 percent gas. We experienced a number of operational and timing issues during 2006, primarily associated with compression, which contributed to the decline in production. Our proved reserves at year-end 2006 were 159.5 BCFE, 44 percent of which were proved developed and 96 percent of which were natural gas. This is a 43 percent increase over 2005 year-end proved reserves of 111.3 BCFE.
The Elm Grove Field is the highest value field in the ArkLaTex region at year-end 2006, with proved reserves of 79.5 BCFE and a PV-10 value of $107.8 million. Elm Grove comprises approximately five percent of the entire Companys PV-10 value. We own interests in 320 wells in the field and our working interest ranges from 0.2 percent to 37.3 percent, with the higher working interests in the southern portion of our acreage. The reserves in this field are comprised of natural gas. The Lower Cotton Valley and Hosston formations are the major reserve contributors in this field.
Our capital budget for the ArkLaTex in 2007 is $131 million, 57 percent of which will be operated by us. The largest part of this years budget relates to our horizontal limestone program where 22 wells are planned for 2007. In 2006, the Company increased its acreage position targeting these limestone formations by 63 percent to approximately 43,000 net acres. We plan to dedicate two rigs to this horizontal program throughout the year. Elm Grove also represents a significant portion of the regions capital budget as development in this field continues to move forward at an aggressive pace. A total of 87 grass roots wells are planned in the field this year, which is a substantial increase from the prior year. In addition to the continued pursuit of the traditional Lower Cotton Valley target, recompletions using coiled tubing assisted fracturing that target the Hosston formation proved to be very successful in 2006. 20 such Hosston recompletions are budgeted for 2007.
Permian Basin Region. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is one of the major producing basins in the United States. Our holdings in the
Permian Basin resulted from a series of property acquisitions beginning in 1996. In December 2006, we acquired oil and natural gas assets in the Sweetie Peck Field in the Midland Basin in the largest acquisition in our history. To manage the significant increase in operated properties associated with the Sweetie Peck acquisition, we opened a regional office in Midland, Texas in early February 2007. Our office in Midland currently has five full-time employees.
In 2006, we spent $275.2 million on capital expenditures in the Permian basin, compared to $7.7 million in the prior year. The substantive majority of this increase related to the acquisition of oil and gas properties in the Sweetie Peck Field. The productive targets for this field are the producing formations of the Spraberry interval including the Spraberry, Leonard, and Wolfcamp formations. We also spent capital in 2006 on our successful waterflood projects in the Delaware Basin of southeastern New Mexico as well as at HJSA Field. Production from the Permian region was 3.2 BCFE in 2006 and 80 percent of the production was oil. Production increased eight percent over the prior year. Year-end 2006 proved reserves were 142.2 BCFE, 58 percent of which were proved developed and 80 percent of which were oil. This represents an increase of 185 percent from 2005 year-end reserves of 49.9 BCFE.
The Sweetie Peck Field comprises eight percent of our total proved reserves and represents the largest value field in the Company, with proved reserves at year-end 2006 of 78.0 BCFE. Currently there are 73 proved developed producing wells and our working interest in each of these wells is either 95 or 100 percent. The PV-10 value for proved developed wells in the field is $219.5 million, which equates to approximately ten percent of our entire PV-10 value.
The capital budget for 2007 in the region is $111 million, of which 80 percent will be operated by the Company. The majority of the increase relates to anticipated drilling at Sweetie Peck and certain non-operated activity in the basin. Fifty-four wells are planned in the Sweetie Peck Field for 2007, all of which will be operated by us. Other projects contemplated in this years budget include continued development at HJSA and infill and optimization projects at the East Shugart Delaware Unit and Parkway Delaware Unit waterflood projects.
Gulf Coast Region. St. Marys presence in south Louisiana dates to the early 1900s when our founders acquired our namesake property in St. Mary Parish, Louisiana abutting the Gulf of Mexico. These 24,914 acres of fee lands yielded $5.0 million of gross oil and gas royalty revenue in 2006. Our Gulf Coast regional presence expanded as a result of the acquisition of King Ranch Energy, Inc. in 1999. In recent years, our team in Houston, Texas has developed an expertise applying DHI technology. This group of 19 full-time employees manages St. Marys diverse activities in our Gulf Coast and Permian Basin regions.
Our 2006 capital expenditures in the Gulf Coast region totaled $65.5 million, which is 78 percent higher than the $36.8 million spent in 2005. The increase was due to a ramp up in activity for our DHI program as well as our participation as non-operator in an intermediate deep water project. We were successful in six out of eight tests in our DHI program in 2006. We had meaningful operated exploratory successes with the Clyde Leger 1 well at the Duson prospect and with the State Tract 345-1 at the Holly prospect. We also participated in two successful new drills and two successful recompletions in the Judge Digby Field located in Point Coupee Parish outside of Baton Rouge, Louisiana. Offshore, the Company had a non-operated exploration success with the Vermillion 101 well, which began flowing to sales in December 2006. Also, in our intermediate deep water program we had an initial discovery with our operating partner at the Zloty prospect where initial production is expected in mid-2008. Production for 2006 in the Gulf Coast region was 9.7 BCFE, 90 percent of which was natural gas. This is a four percent increase in production from the 9.3 BCFE produced in 2005. The increase in production was a result of the successes mentioned above that were brought online in 2006, as well as contribution from a significant royalty well on our fee acreage that produced for a portion of the year. Proved reserves as of year-end 2006, including those related to the fee properties, were 32.2 BCFE, of which 80 percent were proved developed and 93 percent were natural gas. This is a seven percent increase in proved reserves from 30.0 BCFE as of year-end 2005.
The most significant field in the Gulf Coast region is the Judge Digby Field. As of the end of December 2006, this field had a PV-10 value of $34.3 million with 9.7 BCFE of proved reserves. This accounts for less than two percent of the Companys PV-10 value.
Our exploration and development budget in the Gulf Coast region for 2007 is $60 million, which consists of activity for both onshore and offshore projects in Texas and Louisiana as well as low to moderate risk DHI prospects in state and federal waters of the Gulf of Mexico. There is also capital budgeted in 2007 related to intermediate deep water projects for both new prospects as well as commitments resulting from our 2005 and 2006 successes. The majority of this activity will be operated by others as we plan to operate approximately 14 percent of the 2007 forecasted drilling projects.
We spent a total of $282.9 million on acquisitions of proved and unproved oil and gas properties in 2006. Proved reserves contributed from our acquisitions were 99.2 BCFE, of which 49 percent were proved developed and 72 percent were oil. The most significant acquisition this year was that of the oil and gas properties in the Sweetie Peck Field in the Permian Basin from several private parties in December 2006. The adjusted purchase price for these assets was $247.6 million, which is subject to regular and customary post-closing adjustments. At year-end 2006 there were 78.0 BCFE of proved reserves related to this transaction, 48 percent of which were proved developed and 78 percent of which were oil. Our other acquisitions where smaller, niche transactions and related primarily to the Rockies and Mid-Continent regions. In 2006, we also divested properties with 3.1 BCFE of proved reserves, the majority of which related to a tax-deferred exchange in which we exchanged non-core properties in the Uinta Basin of Utah for properties in Richland County, Montana.
Significant acquisitions prior to 2006 include the 2005 acquisitions of Agate Petroleum, Inc. and properties from Wold Oil Properties, Inc. In 2004, we acquired oil and gas properties from Goldmark Engineering, Inc., in the Rocky Mountain region and the Elm Grove Field from Border Company in the ArkLaTex region.
The following table presents summary information with respect to the estimates of our proved oil and gas reserves for each of the years in the three-year period ended December 31, 2006. For all years presented Netherland, Sewell and Associates, Inc. (NSAI) prepared the reserve information for the Companys coalbed natural gas projects at Hanging Woman Basin in the northern Powder River Basin as well as St. Marys non-operated coalbed methane interest in the Green River Basin. We have engaged Ryder Scott Company to review internal engineering estimates for 80 percent of the PV-10 value of our proven conventional oil and gas reserves in 2006. In 2005 and 2004, Ryder Scott prepared the reserve estimates for at least 80 percent of the PV-10 value of our conventional oil and gas assets. St. Mary personnel prepared the reserve estimates for the remainder of all properties. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor costs have been escalated. You should read the following table along with the section entitled Risk FactorsRisks Related to Our BusinessEstimates of oil and gas reserves are not precise.
(1) Reserve life represents the estimated proved reserves at the dates indicated divided by actual production for the preceding 12-month period.
The following table summarizes the average volumes and realized prices, including and excluding the effects of hedging, of oil and gas produced from properties in which St. Mary held an interest during the periods indicated. Also presented is a production cost per MCFE summary for the Company.
As of December 31, 2006, St. Mary had working interests in 2,234 gross (1,050 net) productive oil wells and 3,359 gross (895 net) productive gas wells. Productive wells are either producing wells or wells capable of commercial production although currently shut in. One or more completions in the same wellbore are counted as one well. A well is categorized under state reporting regulations as an oil well or a
gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.
All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not own any drilling equipment. The following table sets forth the wells drilled and recompleted in which St. Mary participated during each of the three years indicated:
(1) Does not include three, nine, and seven gross wells completed on St. Marys fee lands during 2006, 2005 and 2004, respectively, in which we have only a royalty interest.
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases, fee properties, mineral servitudes, and lease options held by St. Mary as of December 31, 2006. Undeveloped acreage includes leasehold interests that may already have been classified as containing proved undeveloped reserves.
(1) Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of St. Marys properties that include multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above.
(2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains estimated proved reserves.
(3) St. Mary holds an overriding royalty interest in an additional 36,021 gross acres in Utah.
(4) Includes interests in Alabama, Kansas, Nebraska and South Dakota.
From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. As of the date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition or results of operations.
There were no matters submitted to a vote of our security holders during the fourth quarter of 2006.
The following table sets forth the names, ages and positions held by St. Marys executive officers. The age of the executive officers is as of February 15, 2007.
(1) Mr. Hellerstein will be retiring as Chief Executive Officer on February 23, 2007, at which time Mr. Best will be appointed to that position. Mr. Hellerstein will remain Chairman of the Board.
Each executive officer has held his respective position during the past five years, except as follows:
Mark A. Hellerstein was appointed Chairman of the Board in September 2002.
Anthony J. Best joined St. Mary in June 2006 as President and Chief Operating Officer. In December 2006, Mr. Best relinquished his position as Chief Operating Officer when Javan D. Ottoson was elected to that office. From 2003 to October 2005, Mr. Best was President and Chief Executive Officer of Pure Resources, Inc., a subsidiary of Unocal, where he managed all of Unocals onshore U.S. assets. From 2000 to 2002, Mr. Best had an energy and leadership consulting practice working with oil and gas firms and non-profit organizations. From 1979 to 2000, Mr. Best was with ARCO in a variety of positions, including a period as PresidentARCO Permian, PresidentARCO Latin America, Field Manager for Prudhoe Bay, and VPExternal Affairs for ARCO Alaska.
Javan D. Ottoson joined St. Mary in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson has been in the oil and gas industry for 22 years, most recently as Senior Vice PresidentDrilling and Engineering at Energy Partners, Ltd. in New Orleans. Mr. Ottoson managed the Permian assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner, Chevron, from 2003 to 2006. Prior to that, Mr. Ottoson worked for ARCO in management and operational roles. These roles included President of ARCO China, Commercial Director of ARCO British, and Vice President of Operations and Development, ARCO Permian.
Jerry R. Schuyler joined St. Mary in December 2003 as Senior Vice President and Regional Manager of the Gulf Coast region. From November 2001 to July 2002, Mr. Schuyler was Senior Vice President and General ManagerEastern Onshore Division for Dominion Exploration & Production, Inc., where he managed all operations and exploration for Dominions Gulf Coast and eastern onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler was Senior Vice President and General Manager of Dominions Onshore U.S. Division, where he managed all operations and exploration for all of Dominions onshore U.S. regions.
Paul M. Veatch was appointed Senior Vice President and Regional Manager of the Mid-Continent region in March 2006. Mr. Veatch joined St. Mary in April 2001 as Regional A & D Engineer. He was
Manager of Engineering from April 2003 to August 2004 and Vice PresidentGeneral Manager, ArkLaTex from August 2004 to March 2006.
David W. Honeyfield was appointed as Chief Financial Officer in May 2005. Mr. Honeyfield joined St. Mary in May 2003 as Vice PresidentFinance, Treasurer, and Secretary. Prior to joining St. Mary, Mr. Honeyfield was Controller and Chief Accounting Officer of Cimarex Energy Co. from September 2002 to May 2003. From April 2002 to September 2002, he was Controller and Chief Accounting Officer of Key Production Company, Inc., which was acquired by Cimarex in September 2002. Prior to joining Key Production Company, Mr. Honeyfield was a senior audit manager with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with Arthur Andersen since January 1991.
Garry A. Wilkening relinquished his position as Controller in January 2007 when Mark T. Solomon was elected to that office. Mr. Wilkening continues to serve as Vice PresidentAdministration. Mr. Wilkening was Vice PresidentAdministration and Controller from 1999 to 2007.
William D. Hart was appointed Vice PresidentGeneral Manager, ArkLaTex in May 2006. Mr. Hart joined the Company as Exploration Manager, Geologist, Shreveport in November 1992. Mr. Hart was Vice President, Geology, ArkLaTex from May 1996 to May 2006.
Mark T. Solomon was appointed Controller in January 2007. Mr. Solomon joined St. Mary in 1996. He served as Financial Reporting Manager from February 1999 to September 2002, Assistant Vice PresidentFinancial Reporting from September 2002 to May 2006 and Assistant Vice President - Assistant Controller from May 2006 to January 2007. Prior to joining St. Mary, Mr. Solomon was an auditor with Ernst & Young LLP.
Executive officers generally are elected at the regular meeting of the Board immediately following the annual stockholders meeting, to serve for the ensuing year or until their successors are duly qualified and elected. The executive officers of St. Mary do not have fixed terms and serve at the discretion of the Board of Directors. Any officer elected or appointed by the Board may be removed by the Board with or without cause, subject to any contractual rights of the person so removed.
Mr. Hellerstein has an employment agreement with St. Mary. The agreement is in effect until June 30, 2007. Upon any termination of the employment of Mr. Hellerstein by St. Mary before June 30, 2007, for any reason other than death, disability or misconduct by Mr. Hellerstein, St. Mary is generally obligated to continue to pay his base salary, additional bonus and incentive compensation, and other fringe benefits until June 30, 2007.
Mr. Best also has an employment agreement with St. Mary. Upon any termination of the employment of Mr. Best by St. Mary for any reason other than death, disability, or misconduct by Mr. Best, St. Mary is generally obligated to continue to pay his base salary and insurance benefits for a period of two years after termination. In addition, upon commencement of employment, Mr. Best received a cash bonus and a special restricted stock award of 20,000 shares that are vested immediately and not subject to forfeiture. Over the next four years Mr. Best is also eligible to earn additional restricted shares in varying amounts, a portion of which are based on the Companys net asset value growth.
There are no family relationships between any executive officer and any other executive officer or director. There are no arrangements or understandings between any officer and any other person pursuant to which that officer was elected.
Market Information. St. Marys common stock is currently traded on the New York Stock Exchange under the symbol SM. The range of high and low sales prices for the quarterly periods in 2006 and 2005, as reported by the New York Stock Exchange and adjusted for the two-for-one stock split effected in the form of a stock dividend which was distributed on March 31, 2005 to shareholders of record as of March 21, 2005, is set forth below:
The following performance graph compares the cumulative total stockholder return on St. Marys common stock for the period December 31, 2001 to December 31, 2006 with the cumulative total return of the Dow Jones U.S. Exploration and Production Broad Index, and the Standard & Poors 500 Stock Index.
The preceding information under the caption Performance Graph shall be deemed to be furnished but not filed with the Securities and Exchange Commission.
Holders. As of February 16, 2007, the number of record holders of St. Marys common stock was 122. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 7,300.
Dividends. St. Mary has paid cash dividends to stockholders every year since 1940. Semi-annual dividends of $0.025 per share were paid in each of the years 1998 through 2004. Semi-annual dividends of $0.05 per share were paid in 2005 and 2006. We expect that our practice of paying dividends on our common stock will continue, although the payment of future dividends will continue to depend on our earnings, capital requirements, financial condition, and other factors. In addition, the payment of dividends is subject to covenants in our credit facility, including the requirement that we maintain certain levels of stockholders equity and the limitation of our annual dividend rate to no more than $0.25 per share per year. Dividends are currently paid on a semi-annual basis. Dividends paid totaled $5.6 million in 2006 and $5.7 million in 2005.
Restricted Shares. Aside from Rule 144 restrictions on shares for insiders, shares subject to transfer restrictions under the provisions of the Employee Stock Purchase Plan, restricted shares issued to directors under the Non-Employee Director Stock Compensation Plan, and restricted shares issued to directors under the 2006 Equity Incentive Compensation Plan (the 2006 Equity Plan), St. Mary has no restricted shares outstanding as of December 31, 2006.
Issuer Purchases of Equity Securities. St. Mary did not repurchase any shares of its common stock during the fourth quarter of 2006.
Equity Compensation Plans. St. Mary has the 2006 Equity Plan under which options and shares of St. Mary common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. Our stockholders have approved this plan. See Note 7Compensation Plans in the Notes to Consolidated Financial Statements included in Part IV, Item 15 of this report for further information about the material terms of these plans. The following table is a summary of the shares of common stock authorized for issuance under our equity compensation plans as of December 31, 2006:
(1) In May 2006 the stockholders approved the 2006 Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, and stock-based awards to key employees, consultants, and members of the Board of Directors of St. Mary or any affiliate of St. Mary. The 2006 Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the St. Mary Land & Exploration Company Restricted Stock Plan, and the St. Mary Land & Exploration Company Non-Employee Director Stock Compensation Plan (collectively referred to as the Predecessor Plans). All grants of equity are now made out of the 2006 Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the 2006 Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances.
(2) Under the St. Mary Land & Exploration Company Employee Stock Purchase Plan (the ESPP), eligible employees may purchase shares of the Companys common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP are restricted for a period of 18 months from the date issued. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code.
The following table sets forth supplemental selected financial and operating data for St. Mary as of the dates and for the periods indicated. The financial data for each of the five years presented were derived from the consolidated financial statements of St. Mary. The following data should be read in conjunction with Managements Discussion and Analysis of Financial Condition and Results of Operations, which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with St. Marys consolidated financial statements included in this report.
This discussion includes forward-looking statements. Please refer to Cautionary Information about Forward-Looking Statements in Part I, Item 1 of this Form 10-K for important information about these types of statements.
We are an independent energy company focused on the exploration, exploitation, development, acquisition, and production of natural gas and crude oil in the United States. We earn 93 percent of our revenues and generate our cash flows from operations primarily from the sale of produced natural gas and crude oil. Our oil and gas reserves and operations are concentrated primarily in various Rocky Mountain Basins, including the Williston, Big Horn, Wind River, Powder River and Greater Green River Basins; the Mid-Continent Anadarko and Arkoma Basins; the Permian Basin; the tight sandstone reservoirs of East Texas, South Texas, and North Louisiana; and the onshore Gulf Coast and offshore Gulf of Mexico. We have developed a balanced portfolio of proved reserves, development drilling opportunities, and non-conventional gas prospects.
As of December 31, 2006, we had estimated proved reserves of 74.2 MMBbls of oil and 482.5 Bcf of natural gas, or 927.6 BCFE with a PV-10 value of $2.2 billion. The after income tax value of $1.6 billion is represented by the standardized measure calculation as presented in Note 12 of Part IV, Item 15 of this report. Our reserves were 78 percent proved developed and 52 percent natural gas. The $2.2 billion PV-10 value for proved reserves is a 13 percent decrease over the prior year. While proved reserves increased 17 percent, adjusted natural gas reserve pricing declined 44 percent year-over-year to $5.64 per MMBtu which had a significant impact on the PV-10 value. Adjusted crude oil reserve pricing at $61.05 per barrel was essentially flat compared to 2005. We added 99.2 BCFE of proved reserves through acquisitions this year, 49 percent of which were proved developed and 72 percent of which were oil. The significant decrease in natural gas prices experienced in 2006 resulted in a downward price revision of 52.2 BCFE. This decline in reserves attributed to downward price revisions was offset by a 66.3 BCFE upward revision for performance. Total production of oil and natural gas increased by six percent in 2006 to 92.8 BCFE. Approximately 61 percent of our 2006 production volumes were derived from sales of natural gas.
Senior Management Transition
During 2006, we underwent or announced personnel changes in the chief operating officer and chief executive officer roles. Doug York, our previous Chief Operating Officer, left us in early 2006 to pursue other professional interests. Mark Hellerstein, our long-serving President and Chief Executive Officer announced in mid-2006 his intention to retire from day-to-day management once a successor could be found. Tony Best, an executive with 28 years of experience in the oil and gas industry, joined us in June 2006 as President and Chief Operating Officer. Mr. Hellerstein and Mr. Best worked together through the second half of 2006 to develop a succession plan whereby Mr. Best would succeed Mr. Hellerstein as chief executive officer in February 2007. Mr. Hellerstein will continue to serve as the Chairman of the Board. With Mr. Best taking over the role of CEO, we hired Jay Ottoson in December 2006 as Executive Vice President and Chief Operating Officer. Mr. Ottoson has 22 years of operational and management experience in the oil and gas industry.
2006 Acquisition of Permian Oil and Natural Gas Assets
On December 14, 2006 we closed on the acquisition of oil and gas properties in the Sweetie Peck Field in West Texas for $247.6 million. This purchase price will be subject to regular and customary post-closing
adjustments for capital, revenues and expenses between the effective and closing dates. The transaction was the largest acquisition in our history. The properties acquired are located in the Midland Basin within the Permian Basin and target the producing formations of the Spraberry interval, which include the Spraberry, Leonard, and Wolfcamp formations. Proved reserves from the acquisition were 78.0 BCFE, 78 percent of which was oil. We acquired 73 producing wells and significant proved undeveloped and unproved potential. Approximately 60 percent of the value was attributable to proved developed producing reserves. The gross daily production rate from this field at the time of acquisition and through the end of 2006 averaged 22.2 MMCFE as of December 31, 2006. We hedged the first five years of oil production related to the transaction using swaps with annual average prices ranging between $65.15 and $68.04 per barrel. The residual natural gas production was hedged over a five year period at a weighted-average equivalent price of roughly $7.70 per MMBtu. We also hedged three years of natural gas liquids production.
This transaction adds low risk properties to our portfolio and significantly increases our presence in the region. The properties are all operated by St. Mary with either a 95 or 100 percent working interest ownership. The acquisition also adds an attractive multi-year drilling program to our inventory. We assumed operations on February 1, 2007, and are currently running two drilling rigs in the field. Our plan is to increase the number of rigs running in the field to four by year end. We are beginning to see an increased availability of drilling rigs, in sharp contrast from the previous two years. The most recent rig utilization report as published by Baker Hughes shows flat to declining utilization in all regions of the lower 48 states with the exception of the Rockies area. This trend is viewed as very favorable to the exploration and production segment of the industry. It would seem that a natural extension of the increased rig availability would be a decreasing contract rate on drilling rigs. However, we have not experienced any significant decreases at the current time.
Reserve Replacement and Growth
Like all oil and gas exploration and production companies, we face the challenge of natural production declines of oil and natural gas resources. An oil and gas exploration and production company depletes part of its asset base with each unit of oil and gas it produces. Historically, we have been able to grow our production despite this natural decline by adding more reserves through acquisitions and drilling activities than we produce. Future growth will depend on our ability to economically continue adding reserves in excess of production.
We believe growth in net asset value per share drives appreciation in our stock price over the long term. Our challenge is to grow net asset value per share. To accomplish this, our goal is to replace at least 200 percent of annual production with new reserves and grow production by ten to 15 percent per year. In 2006, we replaced 244 percent of our production at an all-in finding cost of $3.56 per MCFE. Reserve replacement percentage and finding cost are defined in the glossary at the end of Part I, Item 1 of this report. Excluding acquisitions, we replaced 140 percent of our production at a cost of $4.02 per MCFE. Through acquisition activities, net of divestitures, we replaced 104 percent of production at an acquisition cost of $2.94 per MCFE. We sold reserves representing three percent of our proved reserves at the beginning of the year. We believe annual reserve replacement and finding cost amounts are important analytical measures that are widely used by investors and industry peers in evaluating the performance of oil and gas companies. While single year measurements have some meaning in terms of a trend, we believe that evaluating these items over an extended period of time is a better indication of performance. We note that aberrations, causing both relatively good and bad results, will occur over short intervals of time. Our three-year average reserve replacement percentage is 231 percent and our three-year average finding cost is $2.61 per MCFE. Our all-in finding cost was notably higher in 2006 than in 2005 due to several factors. First, we experienced a downward price revision related to a significant pullback in natural gas prices at the end of 2006. Excluding this price revision, our reserve replacement percentage would have been 300
percent with a finding cost of $2.88 per MCFE. Second, we continued to see price inflation in the drilling and service sector throughout most of the year. Third, several of our drilling programs were not as productive as we had expected for the amount of capital deployed. For example, the Bakken program in the Williston Basin has been a highly successful program over the last several years. However this years results were more marginal and not as productive as wells drilled earlier in the program as we were testing wells closer to the fringe of the play. At the Centrahoma Field in the Arkoma Basin, our first four horizontal Woodford shale wells were moderately economic. Realistically, we believe that there is a capital intensive learning phase at the beginning of every resource play and that we will accrue benefits on future wells in this program as a result of the work performed this year. We are not satisfied with our results in 2006 despite meeting several important internal metrics. We believe we have a program that is somewhat lower in risk and the expectations are that the costs to replace production will be lower in 2007.
Sustainability in our business is dependent on the ability to create new ideas and new value year-after-year. The challenges we face are increasingly more difficult each year as North American oil and gas production continues to decline and other exploration and production companies compete for available reserves. We believe we have a formula for meeting these challenges. We have placed talented geoscientists, engineers, and landmen in each of our regional offices where their experience and knowledge of the local area can be fully utilized. We provide a compensation package that aligns their goals with those of the Company. We support our personnel with a strong balance sheet and fiscal and operating discipline. Even so, we are subject to similar constraints as other companies in the exploration and production industry. Limitations to future growth will be based on overall availability of additional qualified personnel, the availability of drilling rigs to grow our drilling programs, and the generation of new ideas and the utilization of appropriate technology to improve the economics of our operations. We believe that we have sufficient capital resources, that we have the ability to grow our workforce, and that we have the necessary access to drilling rigs in order to execute our $721 million drilling budget for 2007 in a successful and profitable manner.
Oil and Gas Prices
Results of our operations and financial condition are significantly affected by oil and natural gas commodity prices, which fluctuate dramatically. In contrast to 2005 where oil and gas producers benefited from surging commodity prices, 2006 was more challenging as we saw significant volatility in crude oil prices and experienced a severe decline in natural gas prices. Oil price fluctuations are more closely related to global events as opposed to domestic events, although the inability to increase supply domestically continues to be a factor. The global conditions that affect the price of oil include a continuing increase in demand from the global economy, political instability in the Middle East, and a decrease in excess worldwide production capacity. Oil prices reached an all time high in mid-2006 as conflict erupted on the border between Israel and Lebanon and threatened to engulf multiple countries in the region. Tensions eventually cooled and crude oil prices retreated throughout most of the rest of the year, despite OPECs announcement in late 2006 of its intentions to reduce production quotas. The decrease in natural gas prices reflects the return to production of assets impacted by Hurricanes Katrina and Rita in late 2005 as well as the lack of any disruptive hurricane activity in the Gulf of Mexico during the 2006 hurricane season. Mild weather in the 2005/2006 heating season left natural gas storage at high levels for most of the year, which further pressured natural gas prices downward.
Repurchase of Common Stock.
In the second quarter of 2006 we repurchased 3,319,300 shares of our common stock in the open market at a weighted-average price of $37.09 per share, including commissions. In conjunction with the share repurchases that occurred in the second quarter, we also hedged production volumes proportionate to the percentage of outstanding stock that was repurchased. These shares were purchased under a share
repurchase program approved by the Board. We routinely evaluate the market price of our common stock relative to our assessment of net asset value per share. To the extent that the market price per share is below what we believe to be the net asset value per share, we will repurchase shares under the program.
In the third quarter of 2006 the Board authorized an increase to the number of shares available for repurchase to a total of 6,000,000 shares to reload the program for repurchases that occurred in prior years. As of the end of the year we had 6,000,000 shares authorized for repurchase.
We have an active hedging program in which we hedge the first two to five years of an acquisitions risked production. We will also on occasion enter into derivative transactions to hedge a portion of our existing forecasted production. In October 2005, we hedged a significant portion of anticipated future production from our current producing properties using zero-cost collars. We also hedged a portion of specific forecasted natural gas production for 2006, 2007, and 2008 using swap contracts. Taking into account all oil and gas production hedge contracts in place through February 16, 2007, we have hedged anticipated future production of approximately 15 million Bbls of oil, 83 million MMBtu of natural gas, and 40 million gallons of natural gas liquids through the year 2011. We believe we have established an economic base for our future operations, and the spread between the price floors and ceilings on our collars allows us to continue to participate in a higher oil and gas price environment. Please see Note 10 of Part IV, Item 15 of this report for additional information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas Production Hedges in Place, later in this section.
Net Profits Plan
Payments made for distributions from the Net Profits Plan have been expensed as compensation costs in the amount of $26.1 million, $20.8 million, and $8.0 million for the years ended December 31, 2006, 2005, and 2004, respectively. The 2006 payments are lower than originally budgeted due primarily to the unanticipated decrease in natural gas prices in 2006. The actual cash payments we make are dependent on actual production, realized prices, and operating and capital costs associated with the properties in each individual pool. Actual cash payments will be inherently different from the estimated liability amounts.
With respect to the accounting estimate of the liability associated with future estimated payments from our Net Profits Plan, we have recorded $23.8 million of net expense for the year ended December 31, 2006, thereby increasing the long term liability associated with this item. This increase is related to an increase in the estimated prices used to calculate the liability, the accretion of the discount used for the calculation, and the addition of the 2006 pool. While we have forecast that this liability will again increase in 2007, it is not possible to predict this with certainty due to the impact of commodity prices and reserve estimates on the valuation of this estimated liability.
The calculation of the estimated liability associated with the Net Profits Plan requires management to prepare an estimate of future amounts payable from the Net Profits Plan. On a monthly basis, we calculate estimates of the payments to be made for each individual pool under the Net Profits Plan. The underlying principal factors for our estimates are forecasted oil and gas production from the properties that comprise each individual pool, price assumptions, cost assumptions, and discount rate. In most cases, the cash flow streams used in these calculations will span more than 20 years. We generally use a 15 percent discount rate to calculate the present value of these future payments, and the resulting amount is recorded as a liability. Commodity prices impact the calculated cash flows during periods after payout and can dramatically affect the timing of the estimated date of payout of the individual pools. Our commodity price assumptions are currently determined from an average of actual prices realized over the prior 24 months together with adjusted NYMEX strip prices for the ensuing 12 months for a total of 36 months of data. This average is supplemented by including the effect of realized and anticipated hedge prices for the
percentage of forecasted hedged production in the relevant period. The calculation of the estimated liability for the Net Profits Plan is highly sensitive to our price estimates and discount rate assumptions. For example, if we changed the commodity prices in our calculation by five percent, the liability recorded on the balance sheet at December 31, 2006, would differ by approximately $14 million. A one percentage point change in the discount rate would result in a change to the liability of approximately $7 million. We frequently re-evaluate the assumptions used in our calculations and consider the possible impacts stemming from the current market environment including current and future oil and gas prices, discount rates, and overall market conditions.
In 2006, we experienced record production and earnings. Record production is the realization of operational and investment decisions made in prior years as well as the current period. Our record earnings reflect our balanced production profile and high oil prices throughout the year. Our hedging program contributed to our earnings as we received meaningful cash flows from the realization of in-the-money natural gas hedges. We anticipate production for 2007 to be greater than 2006 due to existing and planned wells from the Sweetie Peck Field, expanded drilling programs in most of our regions, and the strength with which we exited 2006. Our operating margins remained strong in 2006 despite being impacted by increasing operating costs and declining natural gas prices. Our 2006 operating margin was $6.28 per MCFE compared to $6.50 per MCFE in 2005.
We had $334.0 million outstanding on our credit facility as of December 31, 2006. The majority of this related to the $247.6 million Sweetie Peck acquisition which closed in late December 2006. Throughout the year, we also utilized our credit facility as needed to fund our exploration and development operations and to repurchase $123.1 million of our common stock.
Net income for 2006 was $190.0 million or $2.94 per diluted share compared to $151.9 million or $2.33 per diluted share for the prior year. Net cash provided by operating activities was $467.7 million, up 14 percent from 2005. Average daily production for the year increased 6 percent to 254.2 MMCFE. Our average net realized price increased $0.04 to $8.18 per MCFE. Unit costs increased for the period as lease operating and transportation expenses increased $0.29 to $1.37 per MCFE, production taxes decreased $0.02 to $0.54 per MCFE, DD&A increased $0.15 to $1.67 per MCFE and general and administrative expense increased $0.05 to $0.42 per MCFE. The significant increase in lease operating costs was a result of some overall increases in oil and gas operating costs, but the majority of this increase was driven by a high level of workover costs throughout the Company.
The table below provides information regarding selected production and financial information for the quarter ended December 31, 2006, and the immediately preceding three quarters. Additional details of per MCFE costs are contained later in this section.